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

FORM 10-Q

(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003

OR

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

Commission File Number: 1-1097

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

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

Oklahoma
(State or other jurisdiction of
incorporation or organization)

73-0382390
(I.R.S. Employer
Identification No.)

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

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

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

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

As of October 31, 2003, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding.

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2003

Part I - FINANCIAL INFORMATION	Page

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

Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations	22

Item 3. Quantitative and Qualitative Disclosures About Market Risk	40

Item 4. Controls and Procedures	40

Part II - OTHER INFORMATION

Item 1. Legal Proceedings	41

Item 6. Exhibits and Reports on Form 8-K	42

Signature	43

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

	September 30, 2003	December 31, 2002
	(In millions)

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5	.3	$	0	.3
Accounts receivable - customers, net		194	.5		97	.7
Accrued unbilled revenues		58	.9		28	.2
Accounts receivable - other, net		---			8	.1
Fuel inventories, at LIFO cost		63	.7		65	.4
Materials and supplies, at average cost		38	.4		40	.7
Accumulated deferred tax assets		7	.3		7	.5
Fuel clause under recoveries		21	.4		14	.7
Other		0	.9		5	.3

Total current assets		390	.4		267	.9


OTHER PROPERTY AND INVESTMENTS, at cost		6	.9		8	.1


PROPERTY, PLANT AND EQUIPMENT
In service		4,192	.4		4,098	.2
Construction work in progress		29	.7		38	.7
Other		1	.0		1	.0

Total property, plant and equipment		4,223	.1		4,137	.9
Less accumulated depreciation		1,984	.9		1,931	.0

Net property, plant and equipment		2,238	.2		2,206	.9


DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges		32	.5		32	.5
Income taxes recoverable from customers, net		31	.8		34	.8
Intangible asset - unamortized prior service cost		37	.8		37	.8
Prepaid benefit obligation		45	.2		29	.6
Price risk management		6	.6		7	.5
Other		32	.9		34	.8

Total deferred charges and other assets		186	.8		177	.0


TOTAL ASSETS	$	2,822	.3	$	2,659	.9

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

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

	September 30, 2003	December 31, 2002
	(In millions)

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	139	.2	$	26	.1
Accounts payable - other		62	.1		63	.2
Advances from parent		9	.1		101	.1
Customers' deposits		34	.4		33	.0
Accrued taxes		29	.8		20	.3
Accrued interest		15	.2		13	.9
Tax collections payable		10	.2		6	.7
Accrued vacation		12	.1		11	.6
Other		15	.1		10	.4

Total current liabilities		327	.2		286	.3


LONG-TERM DEBT		709	.8		710	.5


DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations		152	.2		148	.6
Accumulated deferred income taxes		500	.4		421	.5
Accumulated deferred investment tax credits		43	.3		47	.1
Accrued removal obligations, net		113	.9		109	.3
Provision for payments of take or pay gas		32	.5		32	.5

Total deferred credits and other liabilities		842	.3		759	.0


STOCKHOLDERS' EQUITY
Common stockholders' equity		512	.4		512	.4
Retained earnings		494	.1		455	.2
Accumulated other comprehensive loss, net of tax		(63	.5)		(63	.5)

Total stockholders' equity		943	.0		904	.1

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	2,822	.3	$	2,659	.9

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

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

Three Months Ended September 30,		Nine Months Ended September 30,
2003	2002	2003	2002
	(In millions)

OPERATING REVENUES	$	540	.3	$	488	.9	$	1,230	.9	$	1,103	.2

COST OF GOODS SOLD		266	.1		207	.3		667	.0		534	.2


Gross margin on revenues		274	.2		281	.6		563	.9		569	.0
Other operation and maintenance		71	.5		68	.9		218	.3		209	.1
Depreciation		29	.9		30	.9		91	.7		91	.9
Taxes other than income		12	.0		11	.6		35	.7		35	.2


OPERATING INCOME		160	.8		170	.2		218	.2		232	.8


OTHER INCOME (EXPENSE)
Other income		---			0	.1		0	.5		0	.4
Other expense		(0	.9)		(0	.7)		(2	.1)		(2	.2)

Net other expense		(0	.9)		(0	.6)		(1	.6)		(1	.8)


INTEREST INCOME (EXPENSE)
Interest income		0	.4		0	.3		0	.5		1	.2
Interest on long-term debt		(9	.1)		(9	.6)		(27	.8)		(28	.7)
Allowance for borrowed funds used during construction		0	.1		0	.1		0	.5		0	.8
Interest on short-term debt and other interest charges		(0	.9)		(1	.0)		(2	.7)		(2	.5)

Net interest expense		(9	.5)		(10	.2)		(29	.5)		(29	.2)


INCOME BEFORE TAXES		150	.4		159	.4		187	.1		201	.8

INCOME TAX EXPENSE		55	.3		61	.0		67	.4		74	.1


NET INCOME	$	95	.1	$	98	.4	$	119	.7	$	127	.7

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

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

	Nine Months Ended September 30,
	2003			2002
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	119	.7	$	127	.7
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation		91	.7		91	.9
Deferred income taxes and investment tax credits, net		79	.0		(7	.5)
Other assets		(17	.3)		(40	.3)
Other liabilities		3	.8		(0	.8)
Change in certain current assets and liabilities
Accounts receivable - customers, net		(89	.2)		(49	.0)
Accounts receivable - other, net		0	.6		(4	.2)
Accrued unbilled revenues		(30	.7)		(17	.7)
Fuel, materials and supplies inventories		4	.0		(12	.0)
Fuel clause under recoveries		(6	.6)		(17	.1)
Other current assets		4	.2		4	.2
Accounts payable		(1	.1)		(4	.0)
Accounts payable - affiliates		110	.8		144	.7
Customers' deposits		1	.3		2	.6
Accrued taxes		9	.5		9	.7
Accrued interest		1	.4		1	.0
Fuel clause over recoveries		---			(23	.4)
Other current liabilities		8	.9		8	.4

Net Cash Provided from Operating Activities		290	.0		214	.2


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(114	.4)		(168	.3)

Net Cash Used in Investing Activities		(114	.4)		(168	.3)


CASH FLOWS FROM FINANCING ACTIVITIES
(Decrease) increase in short-term debt, net		(92	.0)		32	.0
Dividends paid on common stock		(78	.6)		(77	.8)

Net Cash Used in Financing Activities		(170	.6)		(45	.8)


NET INCREASE IN CASH AND CASH EQUIVALENTS		5	.0		0	.1
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		0	.3		0	.4

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5	.3	$	0	.5

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

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

1. Summary of Significant Accounting Policies

Organization

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

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the financial position of the Company at September 30, 2003 and December 31, 2002, the results of its operations for the three and nine months ended September 30, 2003 and 2002, and the results of its cash flows for the nine months ended September 30, 2003 and 2002, have been included and are of a normal recurring nature.

Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003 or for any future period. The accompanying condensed 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, 2002.

Accounting Records

The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, the Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. At September 30, 2003 and December 31, 2002, regulatory assets of approximately $58.5 million and approximately $63.9 million, respectively, are being amortized and reflected in rates charged to customers over periods of up to 20 years. At September 30, 2003 and December 31, 2002, regulatory liabilities of approximately $113.9 million and approximately $109.3 million, respectively, have been reclassified from Accumulated Depreciation in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.”

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

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

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

Total Regulatory Assets	$	58	.5	$	63	.9

Regulatory Liabilities
Accrued removal obligations, net	$	113	.9	$	109	.3

Total Regulatory Liabilities	$	113	.9	$	109	.3

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.”

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

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

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

Use of Estimates

In preparing the condensed financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed financial statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s condensed financial statements. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable.

Allowance for Uncollectible Accounts Receivable

All customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable was approximately $2.6 million and $4.7 million at September 30, 2003 and December 31, 2002, respectively.

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. 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 investment tax credits was approximately $1.3 million for the three months ended September 30, 2003 and 2002 and approximately $3.9 million for the nine months ended September 30, 2003 and 2002, respectively, and is recorded as an income tax benefit in the accompanying Condensed Statements of Income.

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

Fair Value of Financial Instruments

The carrying value of the financial instruments on the Condensed Balance Sheets not otherwise discussed in these notes approximates market value.

Cash and Cash Equivalents

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

Revenue Recognition

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

Automatic Fuel Adjustment Clauses

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

Fuel Inventories

Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by

approximately $5.1 million and $7.0 million at September 30, 2003 and December 31, 2002, respectively, based on the average cost of fuel purchased.

Related Party Transactions

Energy Corp. allocated operating costs to the Company of approximately $21.0 million and $23.1 million during the three months ended September 30, 2003 and 2002, respectively, and allocated approximately $63.4 million and $72.4 million during the nine months ended September 30, 2003 and 2002, 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 September 30, 2003 and 2002, the Company paid its affiliate, Enogex Inc. and subsidiaries (“Enogex”), approximately $8.5 million and $8.1 million, respectively, for transporting gas to the Company’s natural gas generating stations. During the nine months ended September 30, 2003 and 2002, the Company paid Enogex approximately $25.0 million and $25.6 million, respectively, for transporting gas to the Company’s natural gas generating stations. These purchases are priced based on a market basket of posted prices within the region and are priced similar to purchases, which had previously been made directly from unaffiliated sources. Approximately $1.7 million was recorded at December 31, 2002 and is included in Accounts Payable — Affiliates in the accompanying Condensed Balance Sheets for these activities. There were no amounts recorded for these activities at September 30, 2003.

During the nine months ended September 30, 2002, the Company recorded interest income of approximately $0.2 million from Energy Corp. for advances made by the Company to Energy Corp. The Company made no advances to Energy Corp. during the three months ended September 30, 2003 and 2002 or during the nine months ended September 30, 2003.

During both the three months ended September 30, 2003 and 2002, the Company recorded interest expense of approximately $0.3 million to Energy Corp. for advances made by Energy Corp. to the Company. During the nine months ended September 30, 2003 and 2002, the Company recorded interest expense of approximately $1.1 million and $0.6 million to Energy Corp. for advances made by Energy Corp. to the Company. The interest rate charged on advances to the Company from Energy Corp. approximates Energy Corp.’s commercial paper rate.

The Company paid approximately $26.3 million and $26.0 million in dividends to Energy Corp. during the three months ended September 30, 2003 and 2002, respectively. The Company paid approximately $78.6 million and $77.8 million in dividends to Energy Corp. during the nine months ended September 30, 2003 and 2002, respectively.

Reclassifications

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

2. Accounting Pronouncements

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

SFAS No. 143 also requires that, if the conditions of SFAS No. 71 are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon adoption of SFAS No. 143, the Company was required to quantify the amount of asset retirement costs previously recovered from ratepayers and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Balance Sheet. At September 30, 2003, the regulatory liability for accrued removal obligations, net was approximately $113.9 million.

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

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

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

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

In April 2003, the FASB issued SFAS No. 149, “Amendments of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain instruments embedded in other contracts and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. This statement requires that contracts with comparable characteristics be accounted for similarly. In particular, this statement clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying hedged risk to conform to language used in Interpretation No. 45 and amends

certain other existing pronouncements. This statement, the provisions of which are to be applied prospectively, is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company adopted this new standard effective July 1, 2003 and the adoption of this new standard did not have a material impact on its financial position or results of operations.

3. Price Risk Management Assets and Liabilities

The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During the nine months ended September 30, 2003 and 2002, the Company’s use of price risk management instruments primarily involved the use of interest rate swap agreements to hedge the Company’s exposure to interest rate risk by converting a portion of the Company’s fixed rate debt to a floating rate. These agreements involve the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount.

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

4. Comprehensive Loss

There were no items of other comprehensive income for the three and nine months ended September 30, 2003 and 2002. Accumulated other comprehensive loss at both September 30, 2003 and December 31, 2002 included approximately a $63.5 million after tax loss ($103.5 million pre-tax) related to a minimum pension liability adjustment. The Company’s

actuarial consultants review the funded status of the pension plan at year end. Any increases or decreases in the minimum pension liability will be reflected in Other Comprehensive Income or Loss in the fourth quarter.

5. Supplemental Cash Flow Information

Non-cash financing activities for the nine months ended September 30, 2003 and 2002, included approximately a $0.9 million decrease and an $8.7 million increase, respectively, related to the change in the fair value of the interest rate swap agreement and the corresponding change in long-term debt.

In connection with the filing in the third quarter of 2003 of Energy Corp.‘s consolidated income tax returns for 2002, Energy Corp. elected to change its tax method of accounting related to the capitalization of costs for self-constructed assets to another method prescribed in the Treasury regulations. The accounting method change is for income tax purposes only. For financial accounting purposes, the only change would be recognition of the impact of the cash flow generated by accelerating income tax deductions. This would be reflected in the financial statements as a switch from current income taxes payable to deferred income taxes payable. This tax accounting method change resulted in a one-time catch-up deduction for costs previously capitalized under the prior method, resulting in a consolidated tax net operating loss for 2002. This tax net operating loss eliminated Energy Corp.’s current federal and state income tax liability for 2002 and all estimated payments made for 2002 have been or will be refunded.

6. Long-Term Debt

Interest Rate Swap Agreement

At September 30, 2003 and December 31, 2002, the Company had one outstanding interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. 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. 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.

At September 30, 2003 and December 31, 2002, the fair value pursuant to the interest rate swap was approximately $6.7 million and $7.5 million, respectively, and was included in non-current Price Risk Management assets in the accompanying Condensed Balance Sheets. A corresponding net increase of approximately $6.7 million and $7.5 million was reflected in Long-Term Debt at September 30, 2003 and December 31, 2002, respectively, as this fair value hedge was effective at September 30, 2003 and December 31, 2002.

S-3 Filing

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

Security Ratings

On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of the Company’s senior unsecured debt from A- to BBB+. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s financial position or results of operations.

On February 5, 2003, Moody’s Investors Service (“Moody’s”) lowered the credit ratings of the Company’s senior unsecured debt to A2 from A1. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s financial position or results of operations.

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

7. Short-Term Debt

The Company had short-term debt from Energy Corp. of approximately $9.1 million and $101.1 million, respectively, outstanding at September 30, 2003 and December 31, 2002. The Company generally uses short-term borrowings from Energy Corp. to meet working capital requirements. As indicated below, the Company also has in place a $100 million line of credit with a bank. The following table shows Energy Corp.’s and the Company’s lines of credit in place at September 30, 2003. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.

	Lines of Credit (In millions)
Entity	Amount	Maturity
Energy Corp. (A)	$ 200.0	January 8, 2004
	100.0	January 15, 2004
	15.0	April 6, 2004
The Company	100.0	June 26, 2004
Total	$ 415.0
(A) The lines of credit at Energy Corp. are used to back up its commercial paper borrowings, which were approximately $63.0 million at September 30, 2003. No borrowings were outstanding at September 30, 2003 under any of the lines of credit shown above; however, $8.0 million of the $15.0 million line of credit above is supported by an Energy Corp. letter of credit.

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

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

8. Commitments and Contingencies

Except as set forth below, the circumstances set forth in Note 9 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002 and in the Notes to the Company’s Condensed Financial Statements included in its Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.

Pending Acquisition of Power Plant

On August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 MW NRG McClain Station (the “McClain Plant”). The acquisition of this interest in the McClain Plant would constitute an acquisition of new generation under the recent OCC settlement order. The purchase price for the interest in the plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. See Note 9 for a further discussion.

Other

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

9. Rate Matters and Regulation

Regulation and Rates

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

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

On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of 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) 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; (iv) the Company to acquire electric generating capacity of not less than 400 megawatts (“MW”) to be integrated into the Company’s generation system. Key portions of the Settlement Agreement are described in detail in Note 10 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002.

As part of the Settlement Agreement, the Company also agreed to consider competitive bidding for gas transportation service to its natural gas fired generation facilities pursuant to the terms set forth in the Settlement Agreement. On April 29, 2003, the Company filed an application with the OCC in which the Company advised the OCC that after careful consideration competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of the Company’s natural gas fired generation plants. A hearing is scheduled to be held in November 2003 and an OCC order in the case is expected either later in 2003 or early in 2004.

On September 15, 2003, the Company filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice lists

the following, among others, as major issues to be addressed in its application: (i) the acquisition of a generation facility in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized, and (iii) increased pension, medical and insurance costs. On October 31, 2003, the Company filed a request with the OCC to increase its rates by approximately $91 million annually. The increase is intended to pay for its acquisition of the McClain Plant, allow for investment in electric system reliability and address rising business costs. The rate plan would reduce rates for schools and more than 80,000 small businesses and non-profit organizations.

Pending Acquisition of Power Plant

On August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the McClain Plant. The acquisition of this interest in the McClain Plant would constitute an acquisition of new generation under the OCC settlement order discussed above. The purchase price for the interest in the plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. The McClain Plant includes gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

Closing is subject to customary conditions including receipt of regulatory approval by the FERC. The asset purchase agreement provides that, unless extended, either party has the right to terminate the contract if the closing does not occur on or before December 1, 2003. Because the current owner of the McClain Plant has filed for bankruptcy protection, the acquisition also is subject to approval by the bankruptcy court. As part of the bankruptcy approval process, NRG McClain LLC’s interest in the plant was subject to an auction process and on October 28, 2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to the Company. Several parties have filed interventions at the FERC opposing the Company’s application under Section 203 of the Federal Power Act to acquire NRG McClain’s interest in the power plant or, alternatively, requesting the FERC to delay approving such acquisition. The Company believes that its application meets the standards under Section 203 set forth by the FERC and that its application will be approved in the near future.

Following the acquisition, the Company expects to operate the plant in accordance with a joint ownership and operating agreement with the OMPA that is in the process of being negotiated. Under this agreement, the Company would operate the facility, and the Company and the OMPA would be entitled to the net available output of the plant based on their respective ownership percentages. All fixed and variable costs would be shared in proportion to the respective ownership interests. The Company expects to utilize its portion of the output, 400 MWs, to serve its native load. As indicated above, the Company filed with the OCC on October 31, 2003, a request to increase its rates to its Oklahoma customers to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. As provided in its most recent rate settlement with the OCC, pending approval of the request to increase base rates to recover the investment in the plant, the Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition, consisting of

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

As part of its most recent rate settlement with the OCC, the Company undertook to acquire electric generating capacity of not less than 400 MWs. The acquisition of a 77 percent interest in the McClain Plant would constitute an acquisition of such generation under the recent OCC settlement order. The Company expects this new generation will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith Cogeneration Project, L.P. (“PowerSmith”) when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers are not expected to affect the profitability of the Company because the Company’s rates would not need to be reduced to accomplish these savings. PowerSmith has filed an application with the OCC seeking to compel the Company to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policies Act of 1978 at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between the Company and PowerSmith or (ii) the avoided cost of the McClain Plant. The Company does not believe that this matter should be heard at the OCC at this time and that the avoided cost requested by PowerSmith is too high. To the extent PowerSmith ultimately were successful, it would reduce the Company’s ability to realize the targeted $75 million of savings to its Oklahoma customers over a three-year period.

As indicated above, the decision of the Company with respect to the purchase of this new generation will be subject to a review by the OCC as a part of a general rate case for the purpose of determining the level of just and reasonable costs associated with the new generation to be included in customers’ rates. The OCC’s review is expected to include, but not be limited to, an analysis and review of the alternatives to purchasing the new generation, the amount paid for such new generation and the level of capacity purchases. The Company will provide monthly reports, for a period of 36 months after the acquisition, to the OCC Staff, documenting and providing proof of savings experienced by the Company’s 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 have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006.

In the event the Company does not acquire the new generation by December 31, 2003, the settlement order requires the Company to credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the new generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. However, if the Company purchases the new generation subsequent to January 1, 2004, the credit to Oklahoma customers will terminate in the first month that the new generation begins initial

operations and any previously-credited amounts to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings.

The Company expects to fund the acquisition with a combination of a capital contribution from Energy Corp., funded in part by Energy Corp.’s recent equity issuance, and the issuance of long-term debt.

Security Enhancements

On August 14, 2002, the Company filed a report with the OCC outlining proposed expenditures and related actions for security enhancement. Attempting to make security investments at the proper level, the Company has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on the Company that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff retained a security expert to review the report filed by the Company. Thereafter, on October 17, 2003, the OCC issued a notice of inquiry seeking comments from the regulated industry for the establishment of guidelines for the protection of critical infrastructure and key assets. The Company currently expects that hearings will be held in early 2004.

Other Regulatory Actions

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

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

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

The Company’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with the Company’s 1996 general rate review and was intended to encourage the Company to lower its fuel costs by: (i)

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

State Restructuring Initiatives

Oklahoma

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

Arkansas

In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed. As part of the repeal

legislation, electric public utilities are permitted to recover transition costs. The Company incurred approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to implement retail open access. The Company’s request to recover these costs is currently being processed by the APSC. The APSC is expected to schedule a hearing early in 2004.

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

Introduction

Company Strategy

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

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

In the near term, the Company plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As discussed in more detail below, on

August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 MW NRG McClain Station (the "McClain Plant"). The Company has filed with the OCC to increase base rates to recover its investment in, and operating expenses of, this power plant and expects that customers should realize overall lower rates. The Company expects that the lower rates will be realized due to fuel savings from the increased efficiency of this new plant, elimination of an existing qualified cogeneration and small power production producers’ contract (“QF contract”) pursuant to which the Company currently acquires a portion of the power it delivers to its customers and termination of a purchased power contract.

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

Forward-Looking Statements

Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit, actions of ratings agencies and their impact on capital expenditures; the Company’s ability to obtain financing on favorable terms; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; completion of the pending acquisition of a power plant; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2002.

Overview

General

The following discussion and analysis presents factors which affected the Company’s results of operations for the three and nine months ended September 30, 2003 as compared to the same periods in 2002 and the Company’s financial position at September 30, 2003. The

following information should be read in conjunction with the Condensed Financial Statements and Notes thereto and the Company’s Form 10-K for the year ended December 31, 2002. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

Operating Results

The Company reported net income of approximately $95.1 million and approximately $98.4 million for the three months ended September 30, 2003 and 2002, respectively. The decrease in net income was primarily attributable to lower electric rates due to the January 2003 rate reduction and lower recoveries of fuel costs from Arkansas customers partially offset by stronger weather-related demand and customer growth in the Company’s service territory.

The Company reported net income of approximately $119.7 million and approximately $127.7 million for the nine months ended September 30, 2003 and 2002, respectively. The decrease in net income was primarily attributable to the lower electric rates due to the January 2003 rate reduction and higher operating and maintenance expenses partially offset by stronger weather-related demand and customer growth in the Company’s service territory.

Regulatory Considerations

On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of 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) 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”); (iv) the Company to acquire electric generating capacity (“New Generation”) of not less than 400 MWs to be integrated into the Company’s generation system.

The Company expects that the New Generation will provide savings, over a three-year period, in excess of $75 million. If the Company is unable to demonstrate at least $75 million in savings, the Company will be required to credit to its Oklahoma customers any unrealized savings below $75 million. In the event the Company does not acquire the New Generation by December 31, 2003, the Company will be required to credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. However, if the Company purchases the New Generation subsequent to January 1, 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any previously-credited amount to Oklahoma customers will be deducted in the determination of the $75.0 million targeted savings. Reference is made to Note 9 of Notes to Condensed Financial Statements in this report and to Note 10 to the Company’s Financial

Statements included in the Company’s Form 10-K for the year ended December 31, 2002 for a further discussion of the Settlement Agreement and of other recent actions relating to the Company’s rates.

On September 15, 2003, the Company filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice lists the following, among others, as major issues to be addressed in its application: (i) the acquisition of a generation facility in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized, and (iii) increased pension, medical and insurance costs. On October 31, 2003, the Company filed a request with the OCC to increase its rates by approximately $91 million annually. The increase is intended to pay for its acquisition of the McClain Plant, allow for investment in electric system reliability and address rising business costs. The rate plan would reduce rates for schools and more than 80,000 small businesses and non-profit organizations.

Pending Acquisition of Power Plant

On August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 MW McClain Plant. The acquisition of this interest in the McClain Plant would constitute an acquisition of new generation under the OCC settlement order discussed above. The purchase price for the interest in the plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. The McClain Plant includes gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent in the McClain Plant is the Oklahoma Municipal Power Authority (“OMPA”).

respective ownership interests. The Company expects to utilize its portion of the output, 400 MWs, to serve its native load. As indicated above, the Company filed with the OCC on October 31, 2003, a request to increase its rates to its Oklahoma customers to recover, among other things, its investment in, and the operating expenses of, the McClain Plant. As provided in its most recent rate settlement with the OCC, pending approval of the request to increase base rates to recover, among other things, the investment in the plant, the Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the investment and ad valorem taxes. Upon approval by the OCC of the Company’s request, all prudently incurred costs accrued through the regulatory asset within the 12-month period will be included in the Company’s prospective cost of service. See “Electric Competition; Regulation” for a further discussion.

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

Outlook

The Company expects net income of between $112 million and $118 million for 2003. For 2004, the financial performance of the Company will depend on regulatory relief. Absent any rate relief, earnings for the Company would be expected to be between $109 million and $113 million.

Results of Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2003			2002			2003			2002
Operating income	$	160.	8	$	170.	2	$	218.	2	$	232.	8
Net income	$	95.	1	$	98.	4	$	119.	7	$	127.	7

In reviewing its operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Statements of Income. Operating income was approximately $160.8 million and $170.2 million for the three months ended September 30, 2003 and 2002, respectively. Operating income was approximately $218.2 million and $232.8 million for the nine months ended September 30, 2003 and 2002, respectively.

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2003			2002			2003			2002
Operating revenues	$	540	.3	$	488	.9	$	1,230	.9	$	1,103	.2
Fuel		181	.9		140	.4		448	.8		338	.2
Purchased power		84	.2		66	.9		218	.2		196	.0

Gross margin on revenues		274	.2		281	.6		563	.9		569	.0
Other operating expenses		113	.4		111	.4		345	.7		336	.2

Operating income	$	160	.8	$	170	.2	$	218	.2	$	232	.8

System sales - MWH (A)		7	.6		7	.5		19	.3		19	.1
Off-system sales - MWH		---			0	.1		0	.1		0	.2

Total sales - MWH		7	.6		7	.6		19	.4		19	.3

(A) Megawatt-hour

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

The Company’s operating income for the three months ended September 30, 2003 decreased approximately $9.4 million or 5.5 percent as compared to the same period in 2002. The decrease in operating income was primarily attributable to lower electric rates due to the January 2003 rate reduction and lower recoveries of fuel costs from Arkansas customers partially offset by stronger weather-related demand and customer growth in the Company’s service territory.

The gross margin, which is operating revenues less cost of goods sold, was approximately $274.2 million for the three months ended September 30, 2003 as compared to approximately $281.6 million during the same period in 2002, a decrease of approximately $7.4 million or 2.6 percent. The gross margin decreased due to lower electric rates resulting from the Company’s rate reduction, which went into effect on January 6, 2003 (approximately $7.4 million), lower recoveries of fuel costs from Arkansas customers through that state’s automatic fuel adjustment clause (approximately $5.6 million) and lower off-system sales (approximately $0.5 million). Partially offsetting the decrease in gross margin was an increase of approximately $4.1 million due to stronger weather-related demand in the Company’s service territory and an increase of approximately $2.1 million due to customer growth.

Cost of goods sold for the Company consists of fuel used in electric generation and purchased power. Fuel expense was approximately $181.9 million for the three months ended September 30, 2003 as compared to approximately $140.4 million during the same period in 2002, an increase of approximately $41.5 million or 29.6 percent. The increase was due primarily to an increase in the average cost of fuel per kilowatt-hour (“kwh”) due to higher natural gas prices. Purchased power costs were approximately $84.2 million for the three months ended September 30, 2003 as compared to approximately $66.9 million during the same period in 2002, an increase of approximately $17.3 million or 25.9 percent. The increase was due to approximately a 51.6 percent increase in the volume of energy purchased primarily due to economic purchases.

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

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $113.4 million for the three months ended September 30, 2003 as compared to approximately $111.4 million during the same period in 2002, an increase of approximately $2.0 million or 1.8 percent. This increase was primarily due to an increase of approximately $3.3 million in pension and benefit expenses and an increase of approximately $1.9 million in miscellaneous other items. These increases were partially offset by a decrease of approximately $1.6 million in uncollectibles expense and a decrease of approximately $1.4 million in outside services.

Nine months ended September 30, 2003 compared to nine months ended September 30, 2002

The Company’s operating income for the nine months ended September 30, 2003 decreased approximately $14.6 million or 6.3 percent as compared to the same period in 2002. The decrease in operating income was primarily attributable to lower electric rates due to the January 2003 rate reduction and higher operating and maintenance expenses partially offset by stronger weather-related demand and customer growth in the Company’s service territory.

The gross margin was approximately $563.9 million for the nine months ended September 30, 2003 as compared to approximately $569.0 million during the same period in 2002, a decrease of approximately $5.1 million or 0.9 percent. Gross margin decreased for the nine months ended September 30, 2003 due to lower electric rates resulting from the Company’s rate reduction (approximately $17.5 million), a decrease of approximately $2.4 million due to the loss of revenue associated with various rate riders and lower off-system sales of approximately $1.3 million. Partially offsetting the decrease in gross margin was an increase of approximately $14.1 million due to customer growth, the loss of revenue in January 2002, associated with the interruption of service to our customers as a result of the severe January 2002 ice storm (approximately $1.5 million) and approximately a $0.8 million increase due to stronger weather-related demand in the Company’s service territory.

Fuel expense was approximately $448.8 million for the nine months ended September 30, 2003 as compared to approximately $338.2 million during the same period in 2002, an increase of approximately $110.6 million or 32.7 percent. The increase was due primarily to an increase in the average cost of fuel per kwh due to higher natural gas prices. Purchased power costs were approximately $218.2 million for the nine months ended September 30, 2003 as compared to approximately $196.0 million during the same period in 2002, an increase of approximately

$22.2 million or 11.3 percent. The increase was primarily due to approximately a 27.7 percent increase in the volume of energy purchased primarily due to economic purchases.

Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $345.7 million for the nine months ended September 30, 2003 as compared to approximately $336.2 million during the same period in 2002, an increase of approximately $9.5 million or 2.8 percent. The increase was primarily due to approximately a $9.2 million increase in operating and maintenance expenses. This increase was primarily due to approximately $5.4 million of costs incurred during the first quarter of 2002 in connection with the severe January 2002 ice storm being reported as a regulatory asset. These 2002 expenditures, incurred by field service personnel, would normally have been charged to maintenance expenses in 2002. Also contributing to the increase in operating and maintenance expenses was an increase of approximately $1.7 million in outside services. Pension and benefit expenses increased approximately $6.8 million for the nine months ended September 30, 2003 as compared to the same period in 2002 due to the general upward trend in these costs. These increases were partially offset by lower levels of uncollectibles expense of approximately $4.5 million.

Net Interest Expense

Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $9.5 million for the three months ended September 30, 2003 as compared to approximately $10.2 million during the same period in 2002, a decrease of approximately $0.7 million or 6.9 percent. This decrease was primarily due to a decrease in variable rate debt interest of approximately $0.3 million and a decrease of approximately $0.2 million related to lower interest rates on outstanding debt achieved from entering into an interest rate swap agreement.

Income Tax Expense

Income tax expense was approximately $55.3 million for the three months ended September 30, 2003 as compared to approximately $61.0 million during the same period in 2002, a decrease of approximately $5.7 million or 9.3 percent. The decrease was primarily due to lower pre-tax income for the three months ended September 30, 2003 as compared to the same period in 2002. In addition, there was a decrease in taxes arising from permanent differences for the three months ended September 30, 2003 as compared to the same period in 2002.

Income tax expense was approximately $67.4 million for the nine months ended September 30, 2003 as compared to approximately $74.1 million during the same period in 2002, a decrease of approximately $6.7 million or 9.0 percent. This decrease was primarily due to lower pre-tax income for the nine months ended September 30, 2003 as compared to the same period in 2002. In addition, there was a decrease in taxes arising from permanent differences for the nine months ended September 30, 2003 as compared to the same period in 2002.

Financial Condition

The balance of Accounts Receivable – Customers, Net was approximately $194.5 million and $97.7 million at September 30, 2003 and December 31, 2002, respectively, an increase of approximately $96.8 million or 99.1 percent. The increase was primarily due to an increase in

the fuel costs for September 2003 as compared to December 2002 and stronger weather-related demand partially offset by the rate reduction ordered in November 2002.

The balance of Accrued Unbilled Revenues was approximately $58.9 million and $28.2 million at September 30, 2003 and December 31, 2002, respectively, an increase of approximately $30.7 million or 108.9 percent. The increase was primarily due to higher fuel costs, higher seasonal electric rates and increased usage due to stronger weather-related demand during September 2003 as compared to December 2002.

The balance of Prepaid Benefit Obligation was approximately $45.2 million and $29.6 million at September 30, 2003 and December 31, 2002, respectively, an increase of approximately $15.6 million or 52.7 percent. The increase was due to the pension plan funding during the third quarter of 2003 partially offset by a decrease due to pension accruals being credited to the prepaid benefit obligation.

The balance of Accounts Payable — Affiliates was approximately $139.2 million and $26.1 million at September 30, 2003 and December 31, 2002, respectively, an increase of approximately $113.1 million. The increase was due to the funding of the pension plan, a dividend payment to Energy Corp. and a net increase due to income tax accruals and payments during the third quarter.

The balance of Advances from Parent was approximately $9.1 million and $101.1 million at September 30, 2003 and December 31, 2002, respectively, a decrease of approximately $92.0 million or 91.0 percent. The decrease was primarily due to payment of ad valorem taxes, bond interest, gas purchases and higher cash received during the third quarter as these are the Company’s peak months to earn revenue.

Liquidity and Capital Requirements

General

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

Income Taxes

In connection with the filing in the third quarter of 2003 of Energy Corp.’s consolidated income tax returns for 2002, Energy Corp. elected to change its tax method of accounting related to the capitalization of costs for self-constructed assets to another method prescribed in the Treasury regulations. The accounting method change is for income tax purposes only. For financial accounting purposes, the only change would be recognition of the impact of the cash flow generated by accelerating income tax deductions. This would be reflected in the financial statements as a switch from current income taxes payable to deferred income taxes payable. This tax accounting method change resulted in a one-time catch-up deduction for costs previously capitalized under the prior method, resulting in a consolidated tax net operating loss for 2002. This tax net operating loss eliminated Energy Corp.’s current federal and state income tax liability for 2002 and all estimated payments made for 2002 have been or will be refunded.

Interest Rate Swap Agreement

At September 30, 2003 and December 31, 2002, the Company had one outstanding interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. This interest rate swap qualified as a fair value hedge under Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and met all of the requirements for a determination that there was no ineffective portion as allowed by the shortcut method under SFAS No. 133. 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.

Future Capital Requirements

The Company’s current 2003 to 2005 construction program includes the purchase of an additional power plant as discussed below; however, the Company will continue to review all of the supply alternatives to replace expiring QF contracts that minimize the total cost of generation to our customers. Unless extended by the Company, 540 MWs of QF contracts will expire over the next one to five years. 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 natural gas prices and the increase in projected natural gas prices, the Company will include the feasibility of constructing additional base load coal-fired units in its build options.

On August 18, 2003, the Company signed an asset purchase agreement to acquire NRG McClain LLC’s 77 percent interest in the 520 MW McClain Plant. The purchase price for the interest in the plant is approximately $159.9 million, subject to adjustment for prepaid gas and property taxes. Closing is subject to numerous conditions. See “Overview – Pending Acquisition of Power Plant.” If approval is received, funding for the acquisition is to be provided by a capital contribution by Energy Corp., utilizing the proceeds received from an equity offering in the third quarter of 2003, and a debt issuance by the Company. To reliably meet the increased electricity needs of the Company’s customers during the foreseeable future, the Company will continue to invest to maintain the integrity of the delivery system. Approximately $4.9 million of the Company’s capital expenditures budgeted for 2003 are to comply with environmental laws and regulations.

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

Future Sources of Financing

General

Apart from the funds required to purchase the McClain Plant discussed above, management expects that internally generated funds will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt. The Company plans to issue debt in the fourth quarter of 2003 to fund a portion of the purchase of the electric generating plant.

Short-Term Debt

Short-term borrowings from Energy Corp. generally are used to meet working capital requirements. As indicated below, the Company also has in place a $100 million line of credit with a bank. The following table shows Energy Corp.’s and the Company’s lines of credit in place at October 31, 2003. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.

	Lines of Credit (In millions)
Entity	Amount	Maturity
Energy Corp. (A)	$ 200.0	January 8, 2004
	100.0	January 15, 2004
	15.0	April 6, 2004
The Company	100.0	June 26, 2004
Total	$ 415.0
(A) The lines of credit at Energy Corp. are used to back up its commercial paper borrowings. There were no commercial paper borrowings outstanding at October 31, 2003. No borrowings were outstanding at October 31, 2003 under any of the lines of credit shown above; however, $8.0 million of the $15.0 million line of credit above is supported by an Energy Corp. letter of credit.

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

Security Ratings

On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of the Company’s senior unsecured debt from A- to BBB+. The outlook is now stable. Standard & Poor’s cited the relatively low-risk low-cost efficient operations of the Company. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s financial position or results of operations.

On February 5, 2003, Moody’s lowered the credit ratings of the Company’s senior unsecured debt to A2 from A1. The outlook for the Company is stable. Moody’s cited the diminished credit profile of the Company with the Company having competitive generation and stable cash flow but with regulatory risk associated with the acquisition of at least 400 MWs of new generation. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s financial position or results of operations.

Critical Accounting Policies and Estimates

The Condensed Financial Statements and Notes to Condensed Financial Statements included in this Form 10-Q and in the Company’s Form 10-K for the year ended December 31, 2002 contain information that is pertinent to Management’s Discussion and Analysis. In preparing the condensed financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed financial statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s condensed financial statements. However, the Company has taken conservative positions, where assumptions and estimates are used, in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s audit committee.

Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. For a discussion of the pension plan rate assumptions, reference is made to Note 8 of the Notes to Financial Statements in the Company’s Form 10-K for the year ended December 31, 2002.

The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Condensed Balance Sheets and in Operating Revenues on the Condensed Statements of Income based on estimates of usage and prices during the period. At September 30, 2003 and December 31, 2002, Accrued Unbilled Revenues were approximately $58.9 million and $28.2 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.

All customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Condensed Balance Sheets and is included in Other Operation and Maintenance Expense on the Condensed Statements of Income. The allowance for uncollectible accounts receivable was approximately $2.6 million and $4.7 million at September 30, 2003 and December 31, 2002, respectively.

Accounting Pronouncements

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

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

recovered from ratepayers and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Balance Sheet. At September 30, 2003, the regulatory liability for accrued removal obligations, net was approximately $113.9 million.

In April 2003, the FASB issued SFAS No. 149, “Amendments of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial

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

Electric Competition; Regulation

Proposed Standard Market Design Rulemaking

In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale electric markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The proposed rule contemplates that all wholesale and retail customers will take transmission service under a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. On April 28, 2003, the FERC issued a White Paper, “Wholesale Market Platform”, in which the FERC indicated that it will change the proposed rule as reflected in the White Paper and following additional regional technical conferences. The FERC committed in the White Paper to work with interested parties including state commissions to find solutions that will recognize regional differences within regions subject to the FERC’s jurisdiction. Thus far, the FERC has held conferences in Boston and Omaha.

Reference is made to Note 8 and Note 9 of Notes to Condensed Financial Statements included in this report and to “Electric Competition; Regulation” in Item 7 of the Company’s Form 10-K for the year ended December 31, 2002 for a discussion of pending regulatory actions involving the Company and of other initiatives to increase competition in the retail and wholesale sale of electricity.

Pending Acquisition of Power Plant

As part of its most recent rate settlement with the OCC, the Company undertook to acquire electric generating capacity of not less than 400 MWs. The acquisition of a 77 percent interest in the McClain Plant discussed above would constitute an acquisition of such generation under the recent OCC settlement order. The Company expects this new generation will provide savings, over a three-year period, in excess of $75.0 million to its Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract with PowerSmith Cogeneration Project, L.P. (“PowerSmith”) when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers are not expected to affect the profitability of the Company because the Company’s rates would not need to be reduced to accomplish these savings. PowerSmith has filed an application with the OCC seeking to compel the Company to continue purchasing power from PowerSmith’s qualified cogeneration facility under the Public Utility Regulatory Policies Act of 1978 at a price that would include an avoided capacity charge equal to the lesser of (i) the rate currently specified in the power purchase agreement between the Company and PowerSmith or (ii) the avoided cost of the McClain Plant. The Company does not believe that this matter should be heard at the OCC at this time and that the avoided cost requested by PowerSmith is too high. To the extent PowerSmith ultimately were successful, it would reduce the Company’s ability to realize the targeted $75 million of savings to its Oklahoma customers over a three-year period.

The decision of the Company with respect to the purchase of this new generation will be subject to a review by the OCC as a part of its general rate case filed October 31, 2003 for the purpose of determining the level of just and reasonable costs associated with the new generation to be included in customers’ rates. The OCC’s review is expected to include, but not be limited to, an analysis and review of the alternatives to purchasing the new generation, the amount paid for such new generation and the level of capacity purchases. The Company will provide monthly reports, for a period of 36 months after the acquisition, to the OCC Staff, documenting and providing proof of savings experienced by the Company’s 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 have an obligation to credit its Oklahoma customers any unrealized savings below $75.0 million as determined at the end of the 36-month period, which shall be no later than December 31, 2006.

Commitments and Contingencies

Pending Acquisition of Power Plant

Other

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

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.

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

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Reference is made to Part I, Item 3 of the Company’s Form 10-K for the year ended December 31, 2002 and to Part II, Item 1 of the Company’s Form 10-Q for the quarters ended March 31, 2003 and June 30, 2003 for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Company and there have been no material changes in the previously reported proceedings, except as set forth below.

Natural Gas Measurement Cases

Will Price (Price I). On September 24, 1999, the Company and Energy Corp. were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs, alleging mismeasurement of natural gas on non-federal lands (Price I). The court entered an order denying class certification on April 10, 2003.

Plaintiffs filed a motion requesting permission to file an amended petition on May 12, 2003, and the court granted such motion on July 28, 2003. In this amended petition, Enogex Inc. and the Company were omitted from the case with two subsidiaries of Enogex remaining as defendants. The Plaintiffs’ amended petition reduces the claims to: (1) mismeasurement of volume only; (2) conspiracy, unjust enrichment and accounting; (3) a putative Plaintiffs’ class of only royalty owners; and (4) gas measured in three specific states.

Energy Corp. intends to vigorously defend this action. Since the case is in the early stages of motions and discovery, Energy Corp. 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.

Item 6. Exhibits and Reports on Form 8-K

(a)	Exhibits

	Exhibit No.	Description

	2.01	Asset Purchase Agreement, dated as of August 18, 2003 by the between the Company and NRG McClain LLC (filed as Exhibit 2.01 to the Company's Form 8-K (file no. 1-1097) filed on August 20, 2003 and incorporated herein by reference).

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

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

(b)	Reports on Form 8-K

The Company filed a Current Report on Form 8-K on July 2, 2003 to report its decision to move its request for a general rate change to later in 2003.

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

The Company filed a Current Report on Form 8-K on August 20, 2003 to report that it signed an asset purchase agreement to acquire a 77 percent interest in the NRG McClain Station.

The Company filed a Current Report on Form 8-K on September 16, 2003 to report that it filed with the Oklahoma Corporation Commission ("OCC") a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent.

The Company filed a Current Report on Form 8-K on October 31, 2003 to report that it filed a request with the OCC to increase its rates by approximately $91 million annually.

The Company filed a Current Report on Form 8-K on November 12, 2003 to report its results of operations and financial condition for the third quarter of 2003.

SIGNATURE

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

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

November 12, 2003

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 officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have:

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

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

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

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

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

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

Date: November 12, 2003

/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: November 12, 2003

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

Exhibit 32.01

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

In connection with the Quarterly Report of Oklahoma Gas and Electric Company (the “Company”) on Form 10-Q for the period ended September 30, 2003, as filed with the Securities and Exchange Commission (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

November 12, 2003

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

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

FORM 10-Q

OR

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2003

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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

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

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

1. Summary of Significant Accounting Policies

Organization

Basis of Presentation

Accounting Records

Use of Estimates

Allowance for Uncollectible Accounts Receivable

Income Taxes

Fair Value of Financial Instruments

Cash and Cash Equivalents

Revenue Recognition

Automatic Fuel Adjustment Clauses

Fuel Inventories

Related Party Transactions

Reclassifications

2. Accounting Pronouncements

3. Price Risk Management Assets and Liabilities

4. Comprehensive Loss

5. Supplemental Cash Flow Information

6. Long-Term Debt

7. Short-Term Debt

8. Commitments and Contingencies

9. Rate Matters and Regulation

Regulation and Rates

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

Introduction

Company Strategy

Forward-Looking Statements

Overview

Outlook

Results of Operations

Financial Condition

Liquidity and Capital Requirements

Future Capital Requirements

Future Sources of Financing

Critical Accounting Policies and Estimates

Accounting Pronouncements

Electric Competition; Regulation

Commitments and Contingencies

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits and Reports on Form 8-K

SIGNATURE

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

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

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

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

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