OKLAHOMA GAS & ELECTRIC CO - FORM 10-Q

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EX-32.01 - OG&AMP;E 2009 3RD QTR 10-Q EX. 32.01 - OKLAHOMA GAS & ELECTRIC CO	ogeande3rdqtr10qex3201.htm
EX-31.01 - OG&AMP;E 2009 3RD QTR 10-Q EX. 31.01 - OKLAHOMA GAS & ELECTRIC CO	ogeande3rdqtr10qex3101.htm

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, 2009

o 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		73-0382390
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

At September 30, 2009, there were 40,378,745 shares of common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2009

TABLE OF CONTENTS

		Page

FORWARD-LOOKING STATEMENTS		1


Part I – FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Condensed Statements of Income		2
Condensed Balance Sheets		3
Condensed Statements of Changes in Stockholder’s Equity		5
Condensed Statements of Cash Flows		6
Notes to Condensed Financial Statements		7

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		39

Item 4. Controls and Procedures		40


Part II – OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 1A. Risk Factors		42

Item 6. Exhibits		43

Signature		44

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” in Oklahoma Gas and Electric Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”) and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

●

general economic conditions, including the availability of credit, access to existing lines of credit, actions of rating agencies and their impact on capital expenditures;

●

Oklahoma Gas and Electric Company’s (the “Company”), a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”), and OGE Energy’s ability to access the capital markets and obtain financing on favorable terms;

●

prices and availability of electricity, coal and natural gas;

●

business conditions in the energy industry;

●

competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;

●

unusual weather;

●

availability and prices of raw materials for current and future construction projects;

●

Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets;

●

environmental laws and regulations that may impact the Company’s operations;

●

changes in accounting standards, rules or guidelines;

●

the discontinuance of accounting principles for certain types of rate-regulated activities;

●

creditworthiness of suppliers, customers and other contractual parties; and

●

other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to the Company’s 2008 Form 10-K.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended							Nine Months Ended
	September 30,							September 30,
(In millions)	2009			2008				2009			2008

OPERATING REVENUES	$	577.9			$	682.5		$	1,339.9		$	1,589.6

COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)		235.7				380.9			595.0			934.2
Gross margin on revenues		342.2				301.6			744.9			655.4
Other operation and maintenance		85.7				79.9			248.9			260.0
Depreciation and amortization		47.3				37.7			138.8			110.9
Impairment of assets		---				---			0.3			---
Taxes other than income		16.0				14.4			48.4			44.9

OPERATING INCOME		193.2				169.6			308.5			239.6

OTHER INCOME (EXPENSE)
Interest income		0.2				1.7			1.0			2.7
Allowance for equity funds used during construction		5.5				---			10.7			---
Other income (loss)		5.9				(1.1	)		14.7			0.7
Other expense		(1.3	)			(0.6	)		(2.5	)		(11.5	)
Net other income (expense)		10.3				---			23.9			(8.1	)

INTEREST EXPENSE
Interest on long-term debt		24.0				16.6			72.3			46.5
Allowance for borrowed funds used during construction		(2.9	)			(0.8	)		(5.9	)		(2.4	)
Interest on short-term debt and other interest charges		1.7				2.9			3.9			11.1
Interest expense		22.8				18.7			70.3			55.2

INCOME BEFORE TAXES		180.7				150.9			262.1			176.3

INCOME TAX EXPENSE		57.5				43.8			81.2			49.6

NET INCOME	$	123.2			$	107.1		$	180.9		$	126.7

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

OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED BALANCE SHEETS

	September 30,		December 31,
	2009		2008
(In millions)	(Unaudited)

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	---	$	50.7
Accounts receivable, less reserve of $1.9 and $2.3, respectively		201.3		172.2
Accrued unbilled revenues		59.5		47.0
Fuel inventories		87.8		56.6
Materials and supplies, at average cost		73.0		67.4
Price risk management		0.2		---
Gas imbalances		0.2		0.6
Accumulated deferred tax assets		2.6		12.7
Fuel clause under recoveries		0.3		24.0
Prepayments		4.8		8.0
Other		2.5		2.3
Total current assets		432.2		441.5

OTHER PROPERTY AND INVESTMENTS, at cost		3.1		3.6

PROPERTY, PLANT AND EQUIPMENT
In service		6,293.4		6,101.1
Construction work in progress		452.2		169.1
Total property, plant and equipment		6,745.6		6,270.2
Less accumulated depreciation		2,395.7		2,314.7
Net property, plant and equipment		4,349.9		3,955.5

DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		20.7		14.6
Benefit obligations regulatory asset		324.4		344.7
McClain Plant deferred expenses		1.6		6.2
Unamortized loss on reacquired debt		16.8		17.7
Unamortized debt issuance costs		11.0		11.4
Other		63.8		56.0
Total deferred charges and other assets		438.3		450.6

TOTAL ASSETS	$	5,223.5	$	4,851.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED BALANCE SHEETS (Continued)

	September 30,		December 31,
	2009		2008
(In millions)	(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	2.4	$	6.4
Accounts payable - other		81.2		105.0
Advances from parent		11.0		17.6
Customer deposits		59.4		56.8
Accrued taxes		41.5		27.9
Accrued interest		20.5		33.2
Accrued compensation		24.4		25.1
Price risk management		0.1		---
Fuel clause over recoveries		176.4		8.6
Other		29.6		26.8
Total current liabilities		446.5		307.4

LONG-TERM DEBT		1,541.7		1,541.4

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		223.3		261.9
Accumulated deferred income taxes		801.4		722.8
Accumulated deferred investment tax credits		14.2		17.3
Accrued removal obligations, net		164.4		150.9
Price risk management liabilities		0.1		---
Other		26.6		25.2
Total deferred credits and other liabilities		1,230.0		1,178.1

Total liabilities		3,218.2		3,026.9

COMMITMENTS AND CONTINGENCIES (NOTE 11)

STOCKHOLDER’S EQUITY
Common stockholder’s equity		958.4		958.4
Retained earnings		1,046.8		865.9
Accumulated other comprehensive income, net of tax		0.1		---
Total stockholder’s equity		2,005.3		1,824.3

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	5,223.5	$	4,851.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY

(Unaudited)

								Accumulated
			Premium					Other
	Common		on Capital		Retained			Comprehensive
(In millions)	Stock		Stock		Earnings			Income (Loss)		Total

Balance at December 31, 2008	$	100.9	$	857.5	$	865.9		$	---	$	1,824.3
Comprehensive income
Net income for first quarter of 2009		---		---		1.3			---		1.3
Comprehensive income		---		---		1.3			---		1.3

Balance at March 31, 2009	$	100.9	$	857.5	$	867.2		$	---	$	1,825.6

Comprehensive income
Net income for second quarter of 2009		---		---		56.4			---		56.4
Comprehensive income		---		---		56.4			---		56.4

Balance at June 30, 2009	$	100.9	$	857.5	$	923.6		$	---	$	1,882.0

Comprehensive income
Net income for third quarter of 2009		---		---		123.2			---		123.2
Other comprehensive income, net of tax
Deferred hedging gains ($0.1 pre-tax)		---		---		---			0.1		0.1
Other comprehensive income		---		---		---			0.1		0.1
Comprehensive income		---		---		123.2			0.1		123.3

Balance at September 30, 2009	$	100.9	$	857.5	$	1,046.8		$	0.1	$	2,005.3

Balance at December 31, 2007	$	100.9	$	564.5	$	757.9		$	---	$	1,423.3
Comprehensive loss
Net loss for first quarter of 2008		---		---		(11.3	)		---		(11.3	)
Comprehensive loss		---		---		(11.3	)		---		(11.3	)

Balance at March 31, 2008	$	100.9	$	564.5	$	746.6		$	---	$	1,412.0

Comprehensive income
Net income for second quarter of 2008		---		---		30.9			---		30.9
Comprehensive income		---		---		30.9			---		30.9
Dividends declared on common stock		---		---		(35.0	)		---		(35.0	)

Balance at June 30, 2008	$	100.9	$	564.5	$	742.5		$	---	$	1,407.9

Comprehensive income
Net income for third quarter of 2008		---		---		107.1			---		107.1
Comprehensive income		---		---		107.1			---		107.1
Capital contribution from OGE Energy		---		293.0		---			---		293.0

Balance at September 30, 2008	$	100.9	$	857.5	$	849.6		$	---	$	1,808.0

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

OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
(In millions)	2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	180.9		$	126.7
Adjustments to reconcile net income to net cash provided from (used in)
operating activities
Depreciation and amortization		138.8			110.9
Impairment of assets		0.3			---
Deferred income taxes and investment tax credits, net		89.3			87.6
Allowance for equity funds used during construction		(10.7	)		---
Loss on disposition of assets		0.6			---
Write-down of regulatory assets		---			9.2
Price risk management assets		(0.2	)		---
Price risk management liabilities		0.2			(1.7	)
Other assets		12.0			(8.1	)
Other liabilities		(60.6	)		(26.9	)
Change in certain current assets and liabilities
Accounts receivable, net		(29.1	)		(73.5	)
Accrued unbilled revenues		(12.5	)		(3.4	)
Fuel, materials and supplies inventories		(36.8	)		(23.3	)
Gas imbalance assets		0.4			0.1
Fuel clause under recoveries		23.7			(82.6	)
Other current assets		3.0			(1.2	)
Accounts payable		(23.8	)		(79.4	)
Accounts payable - affiliates		(4.0	)		(7.6	)
Income taxes payable - affiliates		(7.4	)		(66.3	)
Customer deposits		2.6			1.6
Accrued taxes		13.6			16.4
Accrued interest		(12.7	)		(4.4	)
Accrued compensation		(0.7	)		(7.5	)
Fuel clause over recoveries		167.8			(3.8	)
Other current liabilities		2.8			9.5
Net Cash Provided from (Used in) Operating Activities		437.5			(27.7	)

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(489.5	)		(700.1	)
Proceeds from the sale of assets		0.4			---
Net Cash Used in Investing Activities		(489.1	)		(700.1	)

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term debt, net		0.8			161.9
Proceeds from long-term debt		0.1			444.7
Capital contribution from OGE Energy		---			293.0
Dividends paid on common stock		---			(35.0	)
Retirement of long-term debt		---			(0.1	)
Net Cash Provided from Financing Activities		0.9			864.5

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(50.7	)		136.7
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		50.7			---
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	---		$	136.7
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. The Company is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”) which is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail natural gas business in 1928 and is no longer engaged in the natural 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, 2009 and December 31, 2008, the results of its operations for the three and nine months ended September 30, 2009 and 2008, and the results of its cash flows for the nine months ended September 30, 2009 and 2008, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of subsequent events for inclusion in the Company’s Condensed Financial Statements occurring after September 30, 2009 through October 29, 2009, the date the Company’s financial statements were issued, and, in the opinion of management, the Company’s Condensed Financial Statements and Notes contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009 or for any future period. The Condensed Financial Statements and Notes thereto should be read in conjunction with the audited Financial Statements and Notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”).

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 accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

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

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

	September 30,		December 31,
(In millions)	2009		2008
Regulatory Assets
Benefit obligations regulatory asset	$	324.4	$	344.7
Deferred storm expenses		28.8		32.2
Income taxes recoverable from customers, net		20.7		14.6
Deferred pension plan expenses		19.2		14.6
Unamortized loss on reacquired debt		16.8		17.7
Red Rock deferred expenses		7.8		7.4
McClain Plant deferred expenses		1.6		6.2
Fuel clause under recoveries		0.3		24.0
Miscellaneous		3.1		2.9
Total Regulatory Assets	$	422.7	$	464.3

Regulatory Liabilities
Fuel clause over recoveries	$	176.4	$	8.6
Accrued removal obligations, net		164.4		150.9
Miscellaneous		11.7		4.9
Total Regulatory Liabilities	$	352.5	$	164.4

In accordance with the APSC order received by the Company in May 2009 in its Arkansas rate case, the Company was allowed recovery of its 2006 and 2007 pension settlement costs. During the second quarter of 2009, the Company reduced its pension expense and recorded a regulatory asset for approximately $3.2 million, which is reflected in Deferred Pension Plan Expenses in the table above.

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 accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of which could be significant.

Related Party Transactions

OGE Energy charged operating costs to the Company of approximately $22.9 million and $21.4 million during the three months ended September 30, 2009 and 2008, respectively, and allocated approximately $67.8 million and $68.0 million during the nine months ended September 30, 2009 and 2008, respectively. OGE Energy charges operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one OGE Energy subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, based primarily upon head-count, occupancy, usage or the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

During both the three months ended September 30, 2009 and 2008, the Company recorded an expense from its affiliate, Enogex LLC and its subsidiaries (“Enogex”), of approximately $8.7 million for transporting gas to the Company’s natural gas-fired generating facilities. During both the nine months ended September 30, 2009 and 2008, the Company recorded an expense from Enogex of approximately $26.1 million for transporting gas to the Company’s natural gas-fired generating facilities. During both the three months ended September 30, 2009 and 2008, the Company recorded an expense from Enogex of approximately $3.2 million for natural gas storage services. During both the nine months ended September 30, 2009 and 2008, the Company recorded an expense from Enogex of approximately $9.6 million for natural gas storage services. During the three months ended September 30, 2009 and 2008, the Company also recorded natural gas purchases from its affiliate, OGE Energy Resources, Inc. (“OERI”) of approximately $12.4 million and $24.7 million, respectively. During the nine months ended September 30, 2009 and 2008, the Company also recorded natural gas purchases from OERI of approximately $30.8 million and $68.0 million, respectively. Approximately $2.5 million and $6.6 million were recorded at

September 30, 2009 and December 31, 2008, respectively, and are included in Accounts Payable – Affiliates in the Condensed Balance Sheets for these activities.

On July 1, 2009, the Company, Enogex and OERI entered into hedging transactions to offset natural gas length positions at Enogex with short natural gas exposures at the Company resulting from the cost of generation associated with a wholesale power sales contract with the Oklahoma Municipal Power Authority (“OMPA”). Enogex sold physical natural gas to OERI, and the Company entered into an offsetting natural gas swap with OERI. These transactions are for approximately 50,000 million British thermal units (“MMBtu”) per month from August 2009 to December 2013 (see Note 4 for a further discussion).

During the nine months ended September 30, 2008, the Company recorded interest income of less than $0.1 million from OGE Energy for advances made to OGE Energy from the Company. There was no interest income for the three month periods ended September 30, 2009 and 2008 or for the nine months ended September 30, 2009.

During the three months ended September 30, 2009 and 2008, the Company recorded interest expense of less than $0.1 million and approximately $0.4 million, respectively, for advances made by OGE Energy to the Company. During the nine months ended September 30, 2009 and 2008, the Company recorded interest expense of less than $0.1 million and approximately $0.8 million, respectively, for advances made by OGE Energy to the Company. The interest rate charged on advances to the Company from OGE Energy approximates OGE Energy’s commercial paper rate.

During the nine months ended September 30, 2009 the Company declared no dividends to OGE Energy. During the nine months ended September 30, 2008, the Company declared dividends of approximately $35.0 million to OGE Energy.

On September 25, 2008, OGE Energy made a capital contribution to the Company for approximately $293.0 million.

2. Accounting Development

In 2004, the Company adopted a standard costing model utilizing a fully loaded activity rate (including payroll, benefits, other employee related costs and overhead costs) to be applied to projects eligible for capitalization or deferral. In March 2008, the Company determined that the application of the fully loaded activity rates had unintentionally resulted in the over-capitalization of immaterial amounts of certain payroll, benefits, other employee related costs and overhead costs in prior years. To correct this issue, in March 2008, the Company recorded a pre-tax charge of approximately $9.5 million ($5.8 million after tax) as an increase in Other Operation and Maintenance Expense in the Condensed Statements of Operations for the three months ended March 31, 2008 and a corresponding $8.6 million decrease in Construction Work in Progress and $0.9 million decrease in Other Deferred Charges and Other Assets related to the regulatory asset associated with storm costs in the Condensed Balance Sheets at March 31, 2008.

3. Fair Value Measurements

At September 30, 2009, the Company had approximately $0.2 million of gross derivative assets and approximately $0.2 million of gross derivative liabilities measured at fair value on a recurring basis which are considered level 2 in the fair value hierarchy.

The three levels defined in the fair value hierarchy and examples of each are as follows:

Level 1 inputs are quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. An active market for the asset or liability is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that observable inputs are not available. Unobservable inputs shall reflect the reporting entity’s own

assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). Unobservable inputs shall be developed based on the best information available in the circumstances, which might include the reporting entity’s own data. The reporting entity’s own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

The following table is a summary of the fair value and carrying amount of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management (“PRM”) activities at September 30, 2009 and December 31, 2008.

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
(In millions)	Amount		Value		Amount		Value

Price Risk Management Assets
Energy Derivative Contracts	$	0.2	$	0.2	$	---	$	---

Price Risk Management Liabilities
Energy Derivative Contracts	$	0.2	$	0.2	$	---	$	---

Long-Term Debt
Senior Notes	$	1,406.3	$	1,552.0	$	1,406.1	$	1,327.4
Industrial Authority Bonds		135.4		135.4		135.3		135.3

The carrying value of the financial instruments on the Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.

4.	Derivative Instruments and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. The Company is also exposed to credit risk in its business operations.

Commodity Price Risk

The Company occasionally uses commodity price swap contracts to manage the Company’s commodity price risk exposures. The commodity price swap contracts involve the exchange of fixed price for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity. Natural gas swaps are used to manage the Company’s natural gas exposure related to fuel used in the generation of electricity.

On July 1, 2009, the Company, Enogex and OERI entered into hedging transactions to offset natural gas length positions at Enogex with short natural gas exposures at the Company resulting from the cost of generation associated with a wholesale power sales contract with the OMPA. Enogex sold physical natural gas to OERI, and the Company entered into an offsetting natural gas swap with OERI. These transactions are for approximately 50,000 MMBtu’s per month from August 2009 to December 2013.

Management may designate certain derivative instruments for the purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts. Normal purchases and normal sales contracts are not recorded in PRM assets or liabilities in the Condensed Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to electric power contracts by the Company and fuel procurement by the Company.

The Company recognizes its non-exchange traded derivative instruments as PRM assets or liabilities in the Condensed Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.

Interest Rate Risk

The Company from time to time uses treasury lock agreements to manage its interest rate risk exposure on new debt issuances. Additionally, the Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates.

Credit Risk

The Company is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company’s financial results could be adversely affected and the Company could incur losses.

Cash Flow Hedges

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 or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The ineffectiveness of treasury lock cash flow hedges is measured using the hypothetical derivative method. Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected. Forecasted transactions designated as the hedged transaction in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

At September 30, 2009, the Company had no outstanding treasury lock agreements that were designated as cash flow hedges.

Fair Value Hedges

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. The Company includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.

At September 30, 2009, the Company had no outstanding commodity derivative instruments or treasury lock agreements that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

For derivative instruments that are not designated as either a cash flow or fair value hedge, the gain or loss on the derivative is recognized currently in earnings.

At September 30, 2009, the Company had no material outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge.

Credit-Risk Related Contingent Features in Derivative Instruments

At September 30, 2009, the Company had no derivative instruments that contain credit-risk related contingent features.

5. Stock-Based Compensation

On January 21, 1998, OGE Energy adopted a Stock Incentive Plan (the “1998 Plan”) and in 2003, OGE Energy adopted another Stock Incentive Plan (the “2003 Plan” that replaced the 1998 Plan). In 2008, OGE Energy adopted, and its

shareowners approved, a new Stock Incentive Plan (the “2008 Plan” and together with the 1998 Plan and the 2003 Plan, the “Plans”). The 2008 Plan replaced the 2003 Plan and no further awards will be granted under the 2003 Plan or the 1998 Plan. As under the 2003 Plan and the 1998 Plan, under the 2008 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to 2,750,000 shares under the 2008 Plan.

The Company recorded compensation expense of approximately $0.4 million pre-tax ($0.3 million after tax) and approximately $1.3 million pre-tax ($0.8 million after tax), respectively, during the three and nine months ended September 30, 2009 related to the Company’s portion of OGE Energy’s share-based payments. The Company recorded compensation expense of approximately $0.1 million pre-tax ($0.1 million after tax) and approximately $0.7 million pre-tax ($0.4 million after tax), respectively, during the three and nine months ended September 30, 2008 related to the Company’s portion of OGE Energy’s share-based payments.

OGE Energy issues new shares to satisfy stock option exercises and payouts of earned performance units. During the three and nine months ended September 30, 2009, there were 90,202 shares and 252,950 shares respectively, of common stock issued pursuant to OGE Energy’s Plans related to exercised stock options and payouts of earned performance units, of which 5,968 shares and 39,339 shares, respectively, related to the Company’s employees.

OGE Energy issues restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to risk of forfeiture. OGE Energy awarded 5,487 shares of restricted stock during both the three and nine months ended September 30, 2009, of which none related to the Company’s employees. During the three and nine months ended September 30, 2009, there were 3,321 shares of restricted stock forfeited, of which none related to the Company’s employees.

6. Accumulated Other Comprehensive Income

There was approximately $0.1 million in accumulated other comprehensive income at September 30, 2009 related to deferred hedging activity. There was no accumulated other comprehensive income balance at December 31, 2008.

7. Income Taxes

The Company is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal or state and local income tax examinations by tax authorities for years before 2005. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its Federal investment tax credits on a ratable basis throughout the year. In addition, the Company earns both Federal and Oklahoma state tax credits associated with the production from its 120 megawatt (“MW”) wind farm in northwestern Oklahoma as well as earning Oklahoma state tax credits associated with the Company’s investment in its electric generating facilities which further reduce the Company’s effective tax rate.

As a result of new Internal Revenue Service (“IRS”) proposed regulations related to the deductibility of certain tax assets which were previously capitalized for tax reporting, on December 29, 2008, the Company filed a request with the IRS for a change in its tax method of accounting related to the capitalization of repairs expense. The accounting method change is for income tax purposes only and would allow the Company to record a cumulative tax deduction, if approved by the IRS. For financial accounting purposes, the only change is recognition of the impact of the cash flow generated by accelerating income tax deductions. In June 2009, the Company received a notice from the IRS indicating that its request was under review. As of October 29, 2009, the Company had not received approval of the method.

During the third quarter of 2009, OGE Energy filed its 2008 Federal income tax return which included approximately $211 million in net deductions related to the change of accounting method which generated a net operating loss of approximately $186 million for the 2008 tax year. Because approval for the method change has not been received, the entire asset related to the net operating loss has been accounted for as a reduction in the non-current deferred tax liability until the period in which the change of accounting method is approved. The Company believes approval from the IRS for the accounting method change is highly probable and is expected to occur by the end of 2009.

8. Long-Term Debt

At September 30, 2009, the Company was in compliance with all of its debt agreements.

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

SERIES		DATE DUE	AMOUNT
	0.30% - 1.00%	Garfield Industrial Authority, January 1, 2025	$	47.0
	0.42% - 0.74%	Muskogee Industrial Authority, January 1, 2025		32.4
	0.43% - 0.75%	Muskogee Industrial Authority, June 1, 2027		56.0
Total (redeemable during next 12 months)			$	135.4

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

9. Short-Term Debt

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by loans under short-term bank facilities. There was no short-term debt balance at September 30, 2009 or December 31, 2008. Also, at September 30, 2009 and December 31, 2008, the Company had approximately $11.0 million and $17.6 million, respectively, in outstanding advances from OGE Energy. The following table provides information regarding OGE Energy’s and the Company’s revolving credit agreements and available cash at September 30, 2009.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate			Amount			Weighted-Average
Entity	Commitment			Outstanding (A)			Interest Rate			Maturity
OGE Energy (B)		$	596.0		$	308.0		0.43	% (D)	December 6, 2012
The Company (C)			389.0			11.1		---	% (D)	December 6, 2012
			985.0			319.1		0.43	%
Cash			---			N/A		N/A			N/A
Total		$	985.0		$	319.1		0.43	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2009.

(B) This bank facility is available to back up OGE Energy’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At September 30, 2009, there was approximately $149.0 million in outstanding borrowings under this revolving credit agreement and approximately $159.0 million in outstanding commercial paper borrowings.

(C) This bank facility is available to back up the Company’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At September 30, 2009, there was approximately $11.1 million supporting letters of credit. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at September 30, 2009.

(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements and commercial paper borrowings.

OGE Energy’s and the Company’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the

ratings of OGE Energy or the Company would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade of the Company would also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit.

Unlike OGE Energy, 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 $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2009 and ending December 31, 2010.

10. Retirement Plans and Postretirement Benefit Plans

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

Net Periodic Benefit Cost

	Pension Plan
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2009 (A)		2008 (A)		2009 (B)		2008 (B)
Service cost	$	2.9	$	3.1	$	8.7	$	9.3
Interest cost		6.2		6.2		18.5		18.7
Return on plan assets		(6.6)		(8.6)		(19.8)		(25.7)
Amortization of net loss		4.6		1.8		13.9		5.5
Amortization of unrecognized prior service cost		0.2		0.3		0.7		0.8
Net periodic benefit cost	$	7.3	$	2.8	$	22.0	$	8.6

	Restoration of Retirement Income Plan
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2009 (A)		2008 (A)		2009 (B)		2008 (B)
Amortization of net loss	$	---	$	---	$	0.1	$	0.1
Amortization of unrecognized prior service cost		---		---		0.1		0.1
Net periodic benefit cost	$	---	$	---	$	0.2	$	0.2

(A)

In addition to the $7.3 million and $2.8 million of net periodic benefit cost recognized during the three months ended September 30, 2009 and 2008, respectively, the Company recognized the following:

● a reduction in pension expense during the three months ended September 30, 2009 of less than $0.1 million and an increase in pension expense during the three months ended September 30, 2008 of approximately $2.6 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Deferred Pension Plan Expenses (see Note 1).

(B)

In addition to the $22.2 million and $8.8 million of net periodic benefit cost recognized during the nine months ended September 30, 2009 and 2008, respectively, the Company recognized the following:

● a reduction in pension expense during the nine months ended September 30, 2009 of approximately $2.2 million and an increase in pension expense during the nine months ended September 30, 2008 of approximately $7.6 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Deferred Pension Plan Expenses (see Note 1); and

● a reduction in pension expense during the nine months ended September 30, 2009 of approximately $3.2 million in the Arkansas jurisdiction to reflect the approval of recovery of the Company’s 2006 and 2007 pension settlement costs in the May 2009 Arkansas rate order which are identified as Deferred Pension Plan Expenses (see Note 1).

	Postretirement Benefit Plans
	Three Months Ended								Nine Months Ended
	September 30,								September 30,
(In millions)	2009				2008				2009				2008
Service cost		$	0.5			$	0.6			$	1.6			$	1.8
Interest cost			2.9				2.8				8.6				8.3
Return on plan assets			(1.5	)			(1.5	)			(4.7	)			(4.7	)
Amortization of transition obligation			0.6				0.6				1.9				1.9
Amortization of net loss			0.9				0.9				3.0				2.6
Amortization of unrecognized prior service cost			0.2				0.3				0.6				1.1
Net periodic benefit cost		$	3.6			$	3.7			$	11.0			$	11.0

Pension Plan Funding

In the third quarter of 2009, OGE Energy contributed approximately $10 million to its pension plan, of which approximately $9.3 million was the Company’s portion, for a total contribution of approximately $50 million to its pension plan during 2009, of which approximately $47.0 million was the Company’s portion. No additional contributions are expected in 2009.

11. Commitments and Contingencies

Except as set forth below and in Note 12, the circumstances set forth in Notes 13 and 14 to the Company’s Financial Statements included in the Company’s 2008 Form 10-K appropriately represent, in all material respects, the current status of the Company’s material commitments and contingent liabilities.

Railcar Lease Agreement

At December 31, 2008, the Company had a noncancellable operating lease with purchase options, covering 1,464 coal hopper railcars to transport coal from Wyoming to the Company’s coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through the Company’s tariffs and fuel adjustment clauses. At the end of the lease term, which is January 31, 2011, the Company has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If the Company chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, the Company would be responsible for the difference in those values up to a maximum of approximately $31.5 million.

On February 10, 2009, the Company executed a short-term lease agreement for 270 railcars in accordance with new coal transportation contracts with BNSF Railway and Union Pacific. These railcars were needed to replace railcars that have been taken out of service or destroyed. The lease agreement expires with respect to 135 railcars on March 5, 2010. The lease agreement with respect to the remaining 135 railcars will expire on November 2, 2009, six months from the date those railcars entered the Company’s service on May 2, 2009.

The Company is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.

Coal Transportation Contracts

The Company has transportation contracts for the transportation of coal to its coal-fired power plants. The Company’s transportation contracts expired on December 31, 2008. On December 19, 2008, the Company entered into a new rail transportation agreement with the BNSF Railway for the movement of coal to the Company’s Sooner power plant. The rates in the new agreement were higher than the rates in the Company’s previous transportation contracts.

The Company also filed a complaint at the Surface Transportation Board (“STB”) requesting the establishment of reasonable rates, practices and service terms for the transportation of coal from Union Pacific served mines in the southern Powder River Basin, Wyoming to the Company’s Muskogee power plant. The Company began paying interim shipping rates, subject to refund, while this matter was pending with the STB. On July 24, 2009 the STB issued a decision awarding the Company a reduction in interim shipping rates to its Muskogee plant. In September 2009, the Company received a refund of

approximately $2.7 million from Union Pacific related to payments the Company made in the first quarter of 2009. The Company expects to receive additional refunds for payments it made in the second and third quarters of 2009 by the end of 2009. All refund amounts will be passed through to the Company’s customers.

The overall effect of the new BNSF Railway agreement and rail rate prescription from the STB for rail transportation to the Company’s Sooner and Muskogee power plants is expected to cause an approximate 47 percent annual increase in the Company’s delivered coal prices.

Termination of Wholesale Agreement

On May 28, 2009, the Company sent a termination notice to the Arkansas Valley Electric Cooperative (“AVEC”) that the Company would terminate its wholesale power agreement to all points of delivery where the Company sells or has sold power to AVEC, effective November 30, 2011. The Company is in the process of discussing an agreement with AVEC which could result in the Company supplying wholesale power to AVEC from December 1, 2011 through December 31, 2014. Any such agreement would be conditioned on the FERC and state regulatory approvals. The termination of the AVEC agreement is not expected to have a material impact to the Company’s financial position or results of operations.

Natural Gas Units

In August 2009, the Company issued a request for proposal (“RFP”) for gas supply purchases for periods from November 2009 through March 2010. The gas supply purchases from January through March 2010 account for approximately 15 percent of the Company’s projected 2010 natural gas requirements. The RFP process was completed on September 10, 2009. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2010. Additional gas supplies to fulfill the Company’s remaining 2010 natural gas requirements will be acquired through additional RFPs in early to mid-2010, along with monthly and daily purchases, all of which are expected to be made at market prices.

Coal

In August 2009, the Company issued an RFP for coal supply purchases for periods from January 2011 through December 2015. The coal supply purchases account for approximately 50 percent of the Company’s projected coal requirements during that timeframe. The RFP process is expected to be completed during the fourth quarter of 2009. Additional coal supplies to fulfill the Company’s remaining 2010 through 2015 coal requirements will be acquired through additional RFPs, which are expected to be made at market prices.

Franchise Fee Lawsuit

On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC. In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorized the Company to collect the challenged franchise fee charges. A procedural schedule and notice requirements for the matter were established by the OCC on December 4, 2008. On March 10, 2009, the Oklahoma Attorney General, the Company, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed. A hearing on the motions to dismiss was held before an administrative law judge (“ALJ”) on March 26, 2009. On June 30, 2009, the ALJ issued a report recommending that the application be dismissed. On July 9, 2009, the applicants filed a Notice of Appeal and a hearing on this matter is scheduled for November 5, 2009. The Company believes that this case is without merit.

Natural Gas Measurement Cases

United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the

plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which have resulted in the under reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

In qui tam actions, the Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action.

The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal courts. The consolidated cases are now before the U.S. District Court for the District of Wyoming.

In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that the Company and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming.

On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s district court appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and the Company, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006. The defendants filed motions for attorneys’ fees and other legal costs on various bases. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. On November 15, 2006, Grynberg filed appeals with the Tenth Circuit Court of Appeals. On March 17, 2009, the Tenth Circuit Court of Appeals affirmed the October 2006 order of the District Court of Wyoming dismissing the complaints against all gas defendants, including all Company parties. On April 14, 2009, Grynberg filed a petition for rehearing in the Tenth Circuit Court of Appeals. By order dated May 4, 2009, the Tenth Circuit Court denied Grynberg’s request for rehearing. Grynberg filed a petition for writ of certiorari in the U.S. Supreme Court on August 3, 2009. By order dated October 5, 2009, the U.S. Supreme Court denied Grynberg’s petition for writ of certiorari. This ruling concludes the appeal of the October 2006 order of the District Court of Wyoming dismissing complaints against all gas defendants, including all Company parties. The Company now considers this case closed.

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy 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 the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of OGE Energy’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of OGE Energy’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene.

The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007. On September 18, 2009, the court entered its order denying class certification. On October 2, 2009, the plaintiffs filed for reconsideration of the court’s denial of class certification.

OGE Energy intends to vigorously defend this action. At this time, OGE Energy 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 OGE Energy.

Environmental Laws and Regulations

Air

On March 15, 2005, the U.S. Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the rule. The EPA has stated that it intends to draft new mercury rules under the Federal Clean Air Act. Any costs associated with future mercury regulations are uncertain at this time. Because of the uncertainty caused by the litigation regarding the CAMR, the promulgation of an Oklahoma rule that would have applied to existing facilities has also been delayed. The Company will continue to participate in the state rule making process.

On March 5, 2009, the EPA initiated rulemaking concerning new national emission standards for hazardous air pollutants for existing reciprocating internal combustion engines by proposing amendments to the National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engine Maximum Achievable Control Technology (“RICE MACT Amendments”). Depending on the final regulations that may be enacted by the EPA for the RICE MACT Amendments, Company facilities will likely be impacted. The costs that may be incurred to comply with these regulations, including the testing and modification of the affected engines, are uncertain at this time. The current proposed compliance deadline is three years from the effective date of the final rules.

On April 25, 2005, the EPA published a finding that all 50 states failed to submit the interstate pollution transport plans required by the Clean Air Act as a result of the adoption of the revised ambient ozone and fine particle standards. Failure to submit these implementation plans began a two-year timeframe, starting on May 25, 2005, during which states must submit a demonstration to the EPA that they do not affect air quality in downwind states. The demonstration was properly submitted by the state to the EPA on May 7, 2007, and additional information was submitted by the state to the EPA on December 5, 2007. Because the EPA had not yet approved Oklahoma’s submittal, a third party filed a lawsuit against the EPA in an attempt to force them to act. The outcome of this matter is uncertain at this time.

In September 2005, the Oklahoma Department of Environmental Quality (“ODEQ”) informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in Federal Class I areas. Affected utilities are those which have sources built between 1962 and 1977. These sources must evaluate the installation of Best Available Retrofit Technology (“BART”) to address regional haze. For the Company, the BART-eligible sources include various generating units at various generating stations. The ODEQ made a preliminary determination to accept an application for a waiver from BART requirements for the Horseshoe Lake generating station based on modeling showing no significant impact on visibility in nearby Class I areas. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan (“SIP”) for regional haze.

Waivers were not available for the BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The Company submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of nitrogen oxide (“NOX”) controls on all three units. At the same time, the Company submitted a determination to the ODEQ that an alternative compliance plan for the affected units at the Muskogee and Sooner power plants. The cost for this alternative compliance plan, including the BART compliance plan for the Seminole power plant (the alternative compliance plan and the BART compliance plan are collectively referred to herein as the “alternative plan”), was estimated at approximately $470 million in March 2007. This alternative plan was subject to approval by the ODEQ and the EPA. On November 16, 2007, the ODEQ notified the Company that additional analysis would be required before the Company alternative plan could be accepted. On May 30, 2008, the Company filed the results with the ODEQ for the affected generating units. In this filing, The Company indicated its intention to install low NOX combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. The Company believes that these control measures will achieve visibility improvements in a cost-effective manner. The Company did not propose the installation of scrubbers at its four coal-fired generating units because the Company concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost

of $1.7 billion) would not be cost-effective. The ODEQ has not taken formal action to approve or deny the Company’s plan. The Company is currently in discussions with the ODEQ on what requirements can be included in the SIP as the Company’s BART compliance plan. The original deadline for the ODEQ to submit a SIP for regional haze that includes final BART determinations was December 17, 2007. The ODEQ did not meet this deadline. On January 15, 2009, the EPA published a rule that gives the ODEQ two years to complete the SIP. If the ODEQ fails to meet this deadline, the EPA can issue a Federal implementation plan. Until the BART determination is approved, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty. The Company expects that any necessary environmental expenditures will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from the Company’s retail customers under House Bill 1910, which was enacted into law in May 2005. The EPA Region 6 has commented on the submission. The EPA agreed that good combustion techniques are BART for NOX, but the EPA asked the Company to take a voluntary limit on the availability of the units at Seminole to be consistent with the modeling in the analysis. With respect to the proposal that low sulfur coal is BART for sulfur dioxide (“SO2”), the EPA Region 6 raised two issues. First, the EPA questioned whether the cost projections in the BART analysis continue to be accurate in light of subsequent regulatory and economic developments that could lower demand for scrubbers. Second, the EPA suggested that the projected costs are not “a compelling reason” not to require the installation of scrubbers. The Company has subsequently communicated to the ODEQ that recent cost information shows that the Company’s previous BART analysis is still accurate.

In September 2009, the Company updated its BART analysis with regard to the cost-effectiveness of scrubbers. This revised analysis (in accordance with the EPA precedent) demonstrated that scrubbers were even less cost-effective than previously shown. In addition, on September 23, 2009, the Company proposed an alternative plan for addressing regional haze compliance. This plan involves short-term changes to the dispatching of the Company’s coal units in a way to minimize SO2 emissions and a longer term commitment to achieve reductions that would equate with scrubber installation. This alternative plan would be less expensive than immediate installation of scrubbers and would allow the Company time to consider various other anticipated environmental regulation and legislation before deciding whether to install costly scrubbers. On October 5, 2009, the ODEQ circulated a draft SIP to the Federal land managers with the Bureau of Land Management overseeing the various federal national parks and wildlife areas impacted by regional haze. This SIP suggested that scrubbers would be needed to comply with the regional haze regulations, but noted the Company’s new cost-effectiveness analysis and its alternative plan. The Company continues to advocate for its alternative proposal before the ODEQ, the EPA and the Federal land managers. The Federal land managers will review the SIP for 60 days and the SIP will also be subject to a 30-day public review period before the final filing with the EPA, which is expected to occur in January 2010.

Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone of 0.08 parts per million (“PPM”). In March 2008, the EPA lowered the ambient primary and secondary standards to 0.075 PPM. Oklahoma had until March 2009 to designate any areas of non-attainment within the state, based on ozone levels in 2006 through 2008. Following the state’s designation, the EPA was expected to determine a final designation by March 2010. States were to be required to meet the ambient standards between 2013 and 2030, with deadlines depending on the severity of their ozone level. Oklahoma City and Tulsa were the most likely areas to be designated non-attainment in Oklahoma. On September 16, 2009, the EPA announced that they would reconsider the 2008 national primary and secondary ozone standards to ensure they are scientifically sound and protective of human health. The EPA plans to propose any revisions to the ozone standards by December 2009 and expects to issue a final decision by August 2010. The EPA also proposed to keep the 2008 standards unchanged for the purpose of attainment and non-attainment area designations. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations.

There also is growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation and regulation at the Federal level, actions at the state level, litigation relating to greenhouse gas emissions and pressure for greenhouse gas emission reductions from investor organizations and the international community. Recently, two Federal courts of appeal have reinstated nuisance-type claims against emitters of carbon dioxide, including several utility companies, alleging that such emissions contribute to global warming. On April 17, 2009, the EPA issued a proposed finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. The proposed finding identified six greenhouse gases that pose a potential threat: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride. The EPA is considering public comments on the proposed finding. On September 15, 2009, the EPA proposed rules to reduce greenhouse gas emissions from light-duty vehicles. Final adoption of the proposed standards for light-duty vehicles is contingent on the EPA first finalizing its proposed endangerment finding for greenhouse gas emissions from motor vehicles.

In June 2009, the American Clean Energy and Security Act of 2009 (sometimes referred to as the Waxman-Markey global climate change bill) was passed in the U.S. House of Representatives. The bill includes many provisions that would potentially have a significant impact on the Company and its customers. The bill proposes a cap and trade regime, a renewable portfolio standard, electric efficiency standards, revised transmission policy and mandated investments in plug-in hybrid infrastructure and smart grid technology. Although proposals have been introduced in the U.S. Senate, including a proposal that would require greater reductions in greenhouse gas emissions than the American Clean Energy and Security Act of 2009, it is uncertain at this time whether, and in what form, legislation will be adopted by the U.S. Senate. Both President Obama and the Administrator of the EPA have repeatedly indicated their preference for comprehensive legislation to address this issue and create the framework for a clean energy economy. Compliance with any new laws or regulations regarding the reduction of greenhouse gases could result in significant changes to the Company’s operations, significant capital expenditures by the Company and a significant increase in its cost of conducting business.

On September 22, 2009, the EPA announced the adoption of the first comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The new reporting requirements will apply to suppliers of fossil fuel and industrial chemicals, manufacturers of motor vehicles and engines, as well as large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain Company facilities. The rule requires the collection of data beginning on January 1, 2010 with the first annual reports due to the EPA on March 31, 2011. Certain reporting requirements included in the initial proposed rules that may have significantly affected capital expenditures were not included in the final reporting rule. Additional requirements have been reserved for further review by the EPA with additional rulemaking possible. The outcome of such review and cost of compliance of any additional requirements is uncertain at this time.

On September 30, 2009, the EPA proposed two rules related to the control of greenhouse gas emissions. The first proposal, which is related to the prevention of significant deterioration and Title V tailoring, determines what sources would be affected by requirements under the Federal Clean Air Act programs for new and modified sources to control emissions of carbon dioxide and other greenhouse gas emissions. The second proposal addresses the December 2008 prevention of significant deterioration interpretive memo by the EPA, which declared that carbon dioxide is not covered by the prevention of significant deterioration provisions of the Federal Clean Air Act. The outcome of these proposals is uncertain at this time.

Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and Federal action on climate change issues. The Company reports quarterly its carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Water

The Company filed an Oklahoma Pollutant Discharge Elimination (“OPDES”) permit renewal application with the state of Oklahoma on August 4, 2008 for its Seminole generating station and received a draft permit for review on January 9, 2009. The Company provided comments on the draft permit and will provide additional comments during the public comment period. In addition, the Company filed OPDES permit renewal applications for its Muskogee and Mustang generating stations on March 4, 2009 and April 3, 2009, respectively.

Section 316(b) of the Federal Resource Conservation and Recovery Act and the Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”) requires that the locations, design, construction and capacity of any cooling water intake structure reflect the “best available technology” for minimizing environmental impacts. The EPA Section 316(b) rules for existing facilities became effective July 23, 2004. On January 25, 2007, a Federal court reversed and remanded certain portions of the Section 316(b) rules to the EPA. On July 9, 2007, the EPA suspended these portions of the Section 316(b) rules for existing facilities. As a result of such suspension, permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA completes its review of the suspended sections. In September 2007, the state of Oklahoma required a comprehensive demonstration study be submitted by January 7, 2008 for each affected facility. On January 7, 2008, the Company submitted the requested studies for facilities. Additionally, on April 14, 2008, the U.S. Supreme Court granted writs of certiorari to review the question of whether the Section 316(b) rules authorize the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. On April 1, 2009, the U.S. Supreme Court held that the EPA has

discretion to consider costs relative to benefits in developing cooling water intake structure regulations under Section 316(b) of the Clean Water Act. It was originally anticipated that the State of Oklahoma, using its best professional judgment, would develop Section 316(b) permit requirements prior to any EPA proposal of rules based on the U.S. Supreme Court decision. At the Company’s request, Oklahoma may not require implementation of 316(b) requirements prior to the EPA developing and finalizing their rules. As a result of the EPA’s final 316(b) rules, and the state’s subsequent adoption and implementation, the Company may require additional capital and/or increased operating costs associated with cooling water intake structures at its generating facilities.

Other

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Condensed Financial Statements. Except as otherwise stated above, in Note 12 below, in Item 1 of Part II of this Form 10-Q, in Notes 13 and 14 of Notes to the Company’s Financial Statements included in the Company’s 2008 Form 10-K and in Item 3 of that report, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

12. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 14 to the Company’s Financial Statements included in the Company’s 2008 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

Completed Regulatory Matters

Arkansas Rate Case Filing

On August 29, 2008, the Company filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma and improvements in its system of power lines, substations and related equipment to ensure that the Company can reliably meet growing customer demand for electricity. On March 18, 2009, the Company, the APSC Staff and the Arkansas Attorney General filed a settlement agreement in this matter calling for a general rate increase of approximately $13.6 million. This settlement agreement also allows implementation of the Company’s “time-of-use” tariff which allows participating customers to save on their electricity bills by shifting some of the electricity consumption to times when demand for electricity is lowest. On May 20, 2009, the APSC approved a general rate increase of approximately $13.3 million, which excludes approximately $0.3 million in storm costs discussed below. The Company implemented the new electric rates effective June 1, 2009.

2008 Arkansas Storm Cost Filing

On October 30, 2008, the Company filed an application with the APSC requesting authority to defer its 2008 storm costs that exceed the amount recovered in base rates. The application also requested the APSC to provide for recovery of the deferred 2008 storm costs in the Company’s pending rate case. On December 19, 2008, the APSC issued an order authorizing the Company to defer approximately $0.6 million in 2008 for incremental storm costs in excess of the amount included in the Company’s rates. As discussed above, on March 18, 2009, the Company, the APSC Staff and the Arkansas Attorney General reached a settlement agreement in the Company’s Arkansas rate case which included recovery of these storm costs. As discussed above, in its May 20, 2009 order approving the settlement agreement, the APSC directed the Company to file an exact recovery rider for its 2008 storm costs. The Company filed this recovery rider and the rider was implemented June 1, 2009.

System Hardening Filing

In December 2007, a major ice storm affected the Company’s service territory which resulted in a large number of customer outages. The OCC requested its Staff to review and determine if a rulemaking was warranted. The OCC Staff issued numerous data requests and is in the process of determining if other regulatory jurisdictions have policies or rules requiring

that electric transmission and distribution lines be placed underground. The OCC Staff also surveyed customers. On June 30, 2008, the OCC Staff submitted a report entitled, “Inquiry into Undergrounding Electric Facilities in the State of Oklahoma.” The Company formed a plan to place facilities underground (sometimes referred to as system hardening) with capital expenditures of approximately $115 million over five years for underground facilities, as well as $10 million annually for enhanced vegetation management. On December 2, 2008, the Company filed an application with the OCC requesting approval of its proposed system hardening plan with a recovery rider. On March 20, 2009, all parties to this case signed a settlement agreement recommending a three-year plan that includes up to $35.3 million in capital expenditures and approximately $33.2 million in operating expenses for aggressive vegetation management and a recovery rider. On May 13, 2009, the OCC issued an order approving the settlement agreement in this matter. The new rider, which will allow the Company to recover costs related to system hardening incurred on or after June 15, 2009, was implemented July 1, 2009.

Security Enhancements

On January 15, 2009, the Company filed an application with the OCC to amend its security plan. The Company is seeking approval of new security projects and cost recovery through the previously authorized security rider. The annual revenue requirement is approximately $0.9 million. On May 29, 2009, the OCC issued an order approving a settlement agreement in this matter that incorporated the Company’s requested rate relief. The new rider was implemented June 1, 2009.

FERC Formula Rate Filing

On November 30, 2007, the Company made a filing at the FERC to increase its transmission rates to wholesale customers moving electricity on the Company’s transmission lines. Interventions and protests were due by December 21, 2007. While several parties filed motions to intervene in the docket, only the OMPA filed a protest to the contents of the Company’s filing. The Company filed an answer to the OMPA’s protest on January 7, 2008. On January 31, 2008, the FERC issued an order (i) conditionally accepting the rates; (ii) suspending the effectiveness of such rates for five months, to be effective July 1, 2008, subject to refund; (iii) establishing hearing and settlement judge procedures; and (iv) directing the Company to make a compliance filing. In July 2008, rates were implemented in an annual increase of approximately $2.4 million, subject to refund. On April 24, 2009, the Company and the OMPA filed a settlement agreement with the FERC containing certain revisions to the formula template and protocols for conducting annual updates of wholesale transmission rates. The proposed settlement provides for a $1.3 million increase in revenues from the Company’s transmission customers compared to the $2.4 million increase in revenues previously implemented in July 2008. On May 11, 2009, the Company and the Southwest Power Pool (“SPP”) made a joint filing with the FERC to implement the settlement agreement on an interim basis effective as of May 1, 2009 pending formal action on the settlement agreement by the FERC. The joint motion for interim implementation was granted by the Chief Judge on May 20, 2009. On June 25, 2009, the FERC issued an order approving the Company’s settlement agreement. The Company expects to refund any over collections to its transmission customers beginning in 2010.

2009 Oklahoma Rate Case Filing

On February 27, 2009, the Company filed its rate case with the OCC requesting a rate increase of approximately $110 million. A procedural schedule was established on April 29, 2009 and a preliminary settlement conference was held on June 25 and 26, 2009. On July 2, 2009, the Company announced that it had filed a settlement agreement with the OCC Staff, the Attorney General’s Office of Oklahoma, the Oklahoma Industrial Energy Consumers and other intervenors resolving all issues associated with its requested rate increase. The settlement agreement calls for: (i) an annual net increase of approximately $48.3 million in the Company’s rates to its Oklahoma retail customers, which includes an increase in the residential customer charge from $6.50/month to $13.00/month; (ii) creation of a new recovery rider to permit the recovery of up to $20 million of capital expenditures and operation and maintenance expenses associated with the Company’s smart grid project in Norman, Oklahoma, effective upon completion of the project, which is currently scheduled for July 2010; (iii) continued utilization of an return on equity of 10.75 percent under various recovery riders previously approved by the OCC; and (iv) recovery through the Company’s fuel adjustment clause of approximately $4.8 million annually of certain expenses that historically had been recovered through base rates. The Company expects the impact of the rate increase on its customers and service territory to be minimal over the next 12 months as the rate increase will be more than offset by lower fuel costs attributable to prior fuel over recoveries from lower than forecasted fuel costs. On July 24, 2009, the OCC issued an order approving the settlement agreement. New electric rates were implemented August 3, 2009.

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2007

The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In September 2008, the OCC Staff filed an application for a prudence review of the Company’s 2007 fuel adjustment clause. The Company is required to provide minimum filing requirements (“MFR”) within 60 days of the application; however, the Company requested and was granted an extension to file the MFRs by January 16, 2009, on which date the MFRs were submitted by the Company. A procedural schedule was established on April 24, 2009. On August 12, 2009, all parties to this case signed a settlement agreement in this matter, stating that the Company’s generation and fuel procurement processes and costs during the 2007 calendar year were prudent. A hearing on the settlement agreement was held on September 10, 2009 and the ALJ recommended approval of the settlement agreement. On October 15, 2009, the OCC issued an order adopting the findings in the settlement agreement.

Pending Regulatory Matters

OU Spirit Wind Power Project

The Company signed contracts on July 31, 2008 for approximately 101 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the OU Spirit wind project in western Oklahoma (“OU Spirit”). As discussed below, OU Spirit is part of the Company’s goal to increase its wind power generation portfolio in the near future. On July 30, 2009, the Company filed an application with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct OU Spirit at a cost of approximately $265.8 million. On August 14, 2009, the Company filed its testimony in this matter. On October 15, 2009, all parties to this case signed a settlement agreement that would provide pre-approval of OU Spirit and authorize the Company to begin recovering the costs of OU Spirit through a rider mechanism as the individual turbines are placed into service which is expected in November and December 2009. The settlement agreement also assigns to the Company’s customers the proceeds from the sale of OU Spirit renewable energy credits to the University of Oklahoma. The settlement agreement permits the recovery of up to $270 million of eligible construction costs, including recovery of the costs of the conservation project for the lesser prairie chicken as discussed below; however, the Company may request approval of any cost in excess of $270 million in the Company’s next general rate case. The net impact on the average residential customer’s 2010 electric bill is estimated to be approximately 90 cents per month, decreasing to 80 cents per month in 2011. OU Spirit is expected to be added to the Company’s regulated rate base as part of a general rate case in 2011, at which time the rider would cease. The Company expects to receive an order from the OCC in this matter later in the fourth quarter of 2009. Capital expenditures associated with this project are expected to be approximately $270 million, of which approximately $36 million were incurred in 2008 and approximately $173 million were incurred from January 1, 2009 to September 30, 2009.

In connection with OU Spirit, in January 2008, the Company filed with the SPP for a Large Generator Interconnection Agreement (“LGIA”) for this project. Since January 2008, the SPP has been studying this requested interconnection to determine the feasibility of the request, the impact of the interconnection on the SPP transmission system and the facilities needed to accommodate the interconnection. Given the backlog of interconnection requests at the SPP, there has been significant delay in completing the study process and in the Company receiving a final LGIA. On May 29, 2009, the Company executed an interim LGIA, allowing OU Spirit to interconnect to the transmission grid, subject to certain conditions. In connection with the interim LGIA, the Company posted a letter of credit with the SPP of approximately $10.9 million related to the costs of upgrades required for the Company to obtain transmission service from its new OU Spirit wind farm. The SPP filed the interim LGIA with the FERC on June 29, 2009. On August 27, 2009, the FERC issued an order accepting the interim LGIA, subject to certain conditions, which enables OU Spirit to interconnect into the transmission grid until the final LGIA can be put in place, which is expected by mid-2010.

In connection with OU Spirit and to support the continued development of Oklahoma’s wind resources, on April 1, 2009, the Company announced a $3.75 million project with the Oklahoma Department of Wildlife Conservation to help provide a habitat for the lesser prairie chicken, which ranks as one of Oklahoma’s more imperiled species. Through its efforts, the Company hopes to help offset the effect of wind farm development on the lesser prairie chicken and help ensure that the bird does not reach endangered status, which would significantly limit the ability to develop Oklahoma’s wind potential.

Renewable Energy Filing

wind developers for construction of up to 300 MWs of new capability. In June 2009, the Company announced that it had selected a short list of bidders for a total of 430 MWs and that is was considering acquiring more than the approximately 300 MWs of wind energy originally contemplated in the initial RFP. On September 29, 2009, the Company announced that, from its short list, it had reached agreements with two developers who will build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. The construction of the new wind farms is contingent upon OCC approval of power-purchase agreements negotiated by the Company. Under the terms of the agreements, CPV Keenan will build a 150 MW wind farm in Woodward County and Edison Mission Energy will build a 130 MW facility in Dewey County near Taloga. The agreements are both 20-year power-purchase agreements, under which the developers will build, own and operate the wind generating facilities and the Company will purchase their electric output. The Company expects to file separate applications in October 2009 with the OCC seeking pre-approval for the recovery of the costs associated with purchasing power from these projects. Negotiations with the third bidder on the Company’s short list announced in June, for an additional 150 MWs of wind energy from Texas County were terminated in early October. The Company expects to solicit additional proposals from wind developers in the future with a goal of adding more wind generation in 2011 or 2012.

SPP Transmission/ Substation Projects

In 2007, the SPP notified the Company to construct approximately 44 miles of new 345 kilovolt (“kV”) transmission line which will originate at the existing Company Sooner 345 kV substation and proceed generally in a northerly direction to the Oklahoma/Kansas Stateline (referred to as the Sooner-Rose Hill project). At the Oklahoma/Kansas Stateline, the line will connect to the companion line being constructed in Kansas by Westar Energy. The line is estimated to be in service by April 2012. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

The Company filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma at a cost of approximately $211 million. This transmission line is a critical first step to increased wind development in western Oklahoma. In the application, the Company also requested authorization to implement a recovery rider to be effective when the transmission line is completed and in service, which is expected during 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to the Company’s Oklahoma customers. A settlement agreement was signed by all parties in the matter on July 31, 2008. Under the terms of the settlement agreement, the parties agreed that the Company will: (i) receive pre-approval for construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma and a conclusion that the construction costs of the transmission line are prudent, (ii) receive a recovery rider for the revenue requirement of the $218 million in construction costs and allowance for funds used during construction (“AFUDC”) when the transmission line is completed and in service until new rates are implemented in a subsequent rate case and (iii) to the extent the construction costs and AFUDC for the transmission line exceed $218 million the Company be permitted to show that such additional costs are prudent and allowed to be recovered. On September 11, 2008, the OCC issued an order approving the settlement agreement. At September 30, 2009, the construction costs and AFUDC incurred were approximately $157 million. Separately, on July 29, 2008, the SPP Board of Directors approved the proposed transmission line discussed above. On February 2, 2009, the Company received SPP approval to begin construction of the transmission line and the associated Woodward District Extra High Voltage substation. During the second quarter of 2009, the Company received a favorable outcome in three local court cases challenging the Company’s use of eminent domain to obtain rights-of-way. The Company expects to have additional challenges to the transmission line in another county where rights-of-way are being purchased. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

In January 2009, the Company received notification from the SPP to begin construction on approximately 50 miles of new 345 kV transmission line and substation upgrades at the Company’s Sunnyside substation, among other projects. In April 2009, Western Farmers Electric Cooperative (“WFEC”) assigned to the Company the construction of 50 miles of line designated by the SPP to be built by the WFEC. The new line will extend from the Company’s Sunnyside substation near Ardmore, Oklahoma, approximately 100 miles to the Hugo substation owned by the WFEC near Hugo, Oklahoma. The Company began preliminary line routing and acquisition of rights-of-way in June 2009. When construction is completed, which is expected in April 2012, the SPP will allocate a portion of the annual revenue requirement to the Company customers according to the base-plan funding mechanism as provided in the SPP tariff for application to such improvements. The capital expenditures related to this project are presented in the summary of capital expenditures for known and committed projects in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

On April 28, 2009, the SPP approved a set of 345 kV projects referred to as “Balanced Portfolio 3E”. Balanced Portfolio 3E includes four projects to be built by the Company and includes: (i) construction of approximately 72 miles of transmission line from the Company’s Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at a cost of approximately $105 million for the Company, (ii) construction of approximately 120 miles of transmission line from the Company’s Seminole substation in a northeastern direction to the Company’s Muskogee substation at a cost of approximately $131 million for the Company, (iii) construction of approximately 38 miles of transmission line from the Company’s Sooner substation in an eastern direction to the Grand River Dam Authority Cleveland substation at an estimated cost of approximately $41 million for the Company and (iv) construction of a new substation near Anadarko which is expected to consist of a 345/138 kV transformer and substation breakers and will be built in the Company’s portion of the Cimarron-Lawton East Side 345 kV line at an estimated cost of approximately $8 million for the Company. All of the Balanced Portfolio 3E projects are expected to be in service by April 2014. On June 19, 2009, the Company received a notice to construct the Balanced Portfolio 3E projects from the SPP. On July 23, 2009, the Company responded to the SPP that the Company will construct the Balanced Portfolio 3E projects discussed above. The capital expenditures related to the Balanced Portfolio 3E projects are presented in the summary of capital expenditures for known and committed projects in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Future Capital Requirements.”

Conservation and Energy Efficiency Programs

On September 17, 2009, the Company filed an application with the OCC seeking approval of a comprehensive Demand Program portfolio designed to promote energy efficiency and conservation for each class of Company customers. Eight programs are proposed, ranging from residential weatherization to commercial lighting. In seeking approval of the Demand Programs, the Company also seeks recovery of the program and related costs through a rider that would be added to customers’ electric bills. The Company request is expected to increase the average residential electric bill by less than $1.40 per month. A procedural schedule has not been established in this matter.

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2008

On July 20, 2009, the OCC Staff filed an application for a prudence review of the Company’s 2008 fuel adjustment clause. On September 18, 2009, the MFRs were submitted by the Company. A procedural schedule has not been established in this matter.

Market-Based Rate Authority

On December 22, 2003, the Company and OERI filed a triennial market power update with the FERC based on the supply margin assessment test. On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the generation market power portion of their three year review to address two new interim tests, a pivotal supplier screen test and a market share screen test. On February 7, 2005, the Company and OERI submitted a compliance filing to the FERC that applied the interim tests to the Company and OERI. On June 7, 2005, the FERC issued an order finding that the Company and OERI had failed the market share screen test meant to determine whether entities with market-based rate authority have market power in wholesale power markets. Based on the failed market share screen test, the FERC established a rebuttable presumption that the Company and OERI have the ability to exercise market power in the Company’s control area. On August 8, 2005, the Company and OERI informed the FERC that they would: (i) adopt the FERC default rate mechanism for sales of one week or less to loads that sink in the Company’s control area; and (ii) commit not to enter into any sales with a duration of between one week and one year to loads that sink in the Company’s control area. The Company and OERI also informed the FERC that any new agreements for long-term sales (one year or longer in duration) to loads that sink in the Company’s control area would be filed with the FERC and that the Company and OERI would not make such sales under their respective market-based rate tariffs. On March 21, 2006, the FERC issued an order conditionally accepting the Company’s and OERI’s proposal to mitigate the presumption of market power in the Company’s control area. First, the FERC accepted the additional information related to first-tier markets submitted by the Company and OERI, and concluded that the Company and OERI satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas. Second, the FERC directed the Company and OERI to make certain revisions to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within the Company’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within the Company’s control area (instead of only to sales sinking to load within the Company’s control area). As part of the market-based rate matter, the Company and OERI have filed a series of tariff revisions to comply with the FERC orders and such revisions have been accepted by the FERC. Also, as part of the mitigation for the failed market share screen test discussed above, on an ongoing basis, the Company and OERI file change of

status reports and triennial market power reports according to the FERC orders and regulations. In July 2009, the Company and OERI filed a triennial market power update with the FERC which reported that there have been no significant changes to the Company’s and OERI’s market-based rate authority.

North American Electric Reliability Corporation

The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC approved the North American Electric Reliability Corporation (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. In September 2009, the Company completed a NERC Critical Infrastructure Protection (“CIP”) spot check audit. Resolution of any audit findings is expected in 2010; however, the Company does not expect the resolution of any audit findings to have a material impact on its operations. The Company is subject to a NERC compliance audit every three years as well as periodic spot check audits. The next compliance audit is scheduled for 2011, which will incorporate both NERC CIP and non-CIP standards.

National Legislative Initiatives

In February 2009, the President signed into law the American Recovery and Reinvestment Act of 2009 (“ARRA”). Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy. After review of the ARRA, the Company filed a grant request on August 4, 2009 for $130 million with the U.S. Department of Energy (“DOE”) to be used for the Smart Grid application in the Company’s service territory in Oklahoma. On October 27, 2009, the Company received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million. Receipt of the grant monies is contingent upon successful negotiations with the DOE on final details of the award. The Company is also expected to promptly seek approval from the OCC for matching fund recovery.

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

Introduction

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company’s 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. (“OGE Energy”) which is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Executive Overview

Financial Strategy

OGE Energy’s vision is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. OGE Energy intends to execute its vision by focusing on its regulated electric utility business and unregulated midstream natural gas business conducted by its wholly-owned natural gas pipeline subsidiary, Enogex LLC and its subsidiaries (“Enogex”). OGE Energy intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business. OGE Energy’s financial objectives from 2009 through 2012 include a compound annual earnings growth rate of five to seven percent on a weather-normalized basis as well as an annual dividend growth rate of two percent subject to approval by the Board of Directors. The target payout ratio for OGE Energy is to pay out as dividends no more than 60 percent of its normalized earnings on an annual basis. The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of our shareholder base, our financial position, our growth targets, the composition of our assets and investment opportunities. OGE Energy believes it can accomplish these financial goals by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

Summary of Operating Results

Three Months Ended September 30, 2009 as Compared to Three Months Ended September 30, 2008

The Company reported net income of approximately $123.2 million and $107.1 million, respectively, during the three months ended September 30, 2009 and 2008, an increase of approximately $16.1 million, primarily due to a higher gross margin on revenues (“gross margin”) and higher other income partially offset by higher operation and maintenance expense, higher depreciation and amortization expense and higher income tax expense.

Nine Months Ended September 30, 2009 as Compared to Nine Months Ended September 30, 2008

The Company reported net income of approximately $180.9 million and $126.7 million, respectively, during the nine months ended September 30, 2009 and 2008, an increase of approximately $54.2 million, primarily due to a higher gross margin, higher other income and lower operation and maintenance expense partially offset by higher depreciation and amortization expense, higher interest expense and higher income tax expense.

Recent Developments and Regulatory Matters

Changes in Capital Markets

The volatility in global capital markets experienced in late 2008 and early 2009 led to a reduction in the value of long-term investments held in OGE Energy’s pension trust and postretirement benefit plan trusts. However, more recently in 2009, the market values have partially recovered from the decline in value experienced in late 2008 and early 2009. OGE Energy could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future.

OU Spirit Wind Power Project

The Company signed contracts on July 31, 2008 for approximately 101 megawatts (“MW”) of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the OU Spirit wind project in western Oklahoma (“OU Spirit”). As discussed below, OU Spirit is part of the Company’s goal to increase its wind power generation portfolio in the near future. On July 30, 2009, the Company filed an application with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct OU Spirit at a cost of approximately $265.8 million. On August 14, 2009, the Company filed its testimony in this matter. On October 15, 2009, all parties to this case signed a settlement agreement that would provide pre-approval of OU Spirit and authorize the Company to begin recovering the costs of OU Spirit through a rider mechanism as the individual turbines are placed into service which is expected in November and December 2009. The settlement agreement also assigns to the Company’s customers the proceeds from the sale of OU Spirit renewable energy credits to the University of Oklahoma. The settlement agreement permits the recovery of up to $270 million of eligible construction costs, including recovery of the costs of the conservation project for the lesser prairie chicken as discussed below; however, the Company may request approval of any cost in excess of $270 million in the Company’s next general rate case. The net impact on the average residential customer’s 2010 electric bill is estimated to be approximately 90 cents per month, decreasing to 80 cents per month in 2011. OU Spirit is expected to be added to the Company’s regulated rate base as part of a general rate case in 2011, at which time the rider would cease. The Company expects to receive an order from the OCC in this matter later in the fourth quarter of 2009. Capital expenditures associated with this project are expected to be approximately $270 million, of which approximately $36 million were incurred in 2008 and approximately $173 million were incurred from January 1, 2009 to September 30, 2009.

In connection with OU Spirit, in January 2008, the Company filed with the Southwest Power Pool (“SPP”) for a Large Generator Interconnection Agreement (“LGIA”) for this project. Since January 2008, the SPP has been studying this requested interconnection to determine the feasibility of the request, the impact of the interconnection on the SPP transmission system and the facilities needed to accommodate the interconnection. Given the backlog of interconnection requests at the SPP, there has been significant delay in completing the study process and in the Company receiving a final LGIA. On May 29, 2009, the Company executed an interim LGIA, allowing OU Spirit to interconnect to the transmission grid, subject to certain conditions. In connection with the interim LGIA, the Company posted a letter of credit with the SPP of approximately $10.9 million related to the costs of upgrades required for the Company to obtain transmission service from its new OU Spirit wind farm. The SPP filed the interim LGIA with the FERC on June 29, 2009. On August 27, 2009, the FERC issued an order accepting the interim LGIA, subject to certain conditions, which enables OU Spirit to interconnect into the transmission grid until the final LGIA can be put in place, which is expected by mid-2010.

Renewable Energy Filing

The Company announced in October 2007 its goal to increase its wind power generation over the following four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, the Company issued a request for proposal (“RFP”) to wind developers for construction of up to 300 MWs of new capability. In June 2009, the Company announced that it had selected a short list of bidders for a total of 430 MWs and that is was considering acquiring more than the approximately 300 MWs of wind energy originally contemplated in the initial RFP. On September 29, 2009, the Company announced that, from its short list, it had reached agreements with two developers who will build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. The construction of the new wind farms is contingent upon OCC approval of power-purchase agreements negotiated by the Company. Under the terms of the agreements, CPV Keenan will build a 150 MW wind farm in Woodward County and Edison Mission Energy will build a 130 MW facility in Dewey County near Taloga. The agreements are both 20-year power-purchase agreements, under which the developers will build, own and operate the wind generating facilities and the Company will purchase their electric output. The Company expects to file separate applications in October 2009 with the OCC seeking pre-approval for the recovery of the costs associated with purchasing power from these projects. Negotiations with the third bidder on the Company’s short list announced in June, for an additional 150 MWs of wind energy from Texas County were terminated in early October. The Company expects to solicit additional proposals from wind developers in the future with a goal of adding more wind generation in 2011 or 2012.

2009 Outlook

OGE Energy’s 2009 earnings guidance with respect to the Company remains unchanged. See “2009 Outlook” in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 for a description of the key factors and assumptions underlying this guidance.

2010 Outlook

OGE Energy projects the Company to earn approximately $207 million to $217 million in 2010. The key factors and assumptions include:

●

Normal weather patterns are experienced for the year;

●

Gross margin on revenues of approximately $1.05 billion to $1.06 billion. The key assumptions for gross margin are listed below:

●

Sales growth of approximately 0.9 percent on a weather adjusted basis;

●

OU Spirit is approved by the OCC and the rider is effective January 1, 2010; and

●

The Oklahoma City, Oklahoma to Woodward, Oklahoma transmission line, otherwise known as Windspeed, is in service with the rider effective April 1, 2010;

●

Operating expenses of approximately $655 million to $665 million, with operation and maintenance expenses comprising approximately 60 percent of total;

●

Interest expense of approximately $105 million to $115 million, which assumes approximately $250 million of additional long-term debt issued by the Company in mid-2010;

●

Allowance for equity funds used during construction (“AEFUDC”) income of approximately $5 million; and

●

An effective tax rate of approximately 27 percent.

The Company has significant seasonality in its earnings. The Company typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

Results of Operations

The following discussion and analysis presents factors that affected the Company’s results of operations for the three and nine months ended September 30, 2009 as compared to the same period in 2008 and the Company’s financial position at

September 30, 2009. Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009 or for any future period. The following information should be read in conjunction with the Condensed Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2009		2008			2009		2008
Operating income	$	193.2	$	169.6		$	308.5	$	239.6
Net income	$	123.2	$	107.1		$	180.9	$	126.7

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(Dollars in millions)	2009		2008			2009			2008
Operating revenues	$	577.9	$	682.5		$	1,339.9		$	1,589.6
Cost of goods sold		235.7		380.9			595.0			934.2
Gross margin on revenues		342.2		301.6			744.9			655.4
Other operation and maintenance		85.7		79.9			248.9			260.0
Depreciation and amortization		47.3		37.7			138.8			110.9
Impairment of assets		---		---			0.3			---
Taxes other than income		16.0		14.4			48.4			44.9
Operating income		193.2		169.6			308.5			239.6
Interest income		0.2		1.7			1.0			2.7
Allowance for equity funds used during construction		5.5		---			10.7			---
Other income (loss)		5.9		(1.1	)		14.7			0.7
Other expense		1.3		0.6			2.5			11.5
Interest expense		22.8		18.7			70.3			55.2
Income tax expense		57.5		43.8			81.2			49.6
Net income	$	123.2	$	107.1		$	180.9		$	126.7
Operating revenues by classification
Residential	$	253.4	$	285.4		$	557.3		$	617.1
Commercial		144.4		169.0			336.1			385.0
Industrial		52.5		71.9			128.3			178.4
Oilfield		38.4		47.6			100.5			120.3
Public authorities and street light		54.0		66.0			126.8			153.7
Sales for resale		15.3		20.3			40.0			52.1
Provision for rate refund		---		(0.2	)		(0.6	)		(0.2	)
System sales revenues		558.0		660.0			1,289.4			1,506.4
Off-system sales revenues		11.1		13.5			25.6			59.0
Other		8.8		9.0			25.9			24.2
Total operating revenues	$	577.9	$	682.5		$	1,339.9		$	1,589.6
MWH (A) sales by classification (in millions)
Residential		2.7		2.8			6.8			7.0
Commercial		1.8		1.8			4.9			4.9
Industrial		1.0		1.1			2.7			3.1
Oilfield		0.8		0.8			2.2			2.2
Public authorities and street light		0.8		0.9			2.2			2.3
Sales for resale		0.4		0.4			1.0			1.1
System sales		7.5		7.8			19.8			20.6
Off-system sales		0.3		0.3			0.8			1.0
Total sales		7.8		8.1			20.6			21.6
Number of customers		775,863		768,857			775,863			768,857
Average cost of energy per KWH (B) – cents
Natural gas		3.468		9.962			3.497			9.362
Coal		1.886		1.181			1.737			1.144
Total fuel		2.575		4.033			2.394			3.648
Total fuel and purchased power		2.803		4.410			2.677			4.038
Degree days (C)
Heating - Actual		17		2			1,946			2,036
Heating - Normal		29		29			2,228			2,247
Cooling - Actual		1,189		1,290			1,849			2,023
Cooling - Normal		1,295		1,295			1,850			1,851

(A)	Megawatt-hour.

(B)	Kilowatt-hour.

(C)

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

Three Months Ended September 30, 2009 as Compared to Three Months Ended September 30, 2008

Operating Income

The Company’s operating income increased approximately $23.6 million during the three months ended September 30, 2009 as compared to the same period in 2008 primarily due to a higher gross margin partially offset by higher operation and maintenance expense, higher depreciation and amortization expense and higher taxes other than income.

Gross Margin

Gross margin was approximately $342.2 million during the three months ended September 30, 2009 as compared to approximately $301.6 million during the same period in 2008, an increase of approximately $40.6 million, or 13.5 percent. The gross margin increased primarily due to:

●

increased price variance, which included revenues related to the recovery through rates of the acquisition and operating costs of the 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (“Redbud Facility”), new revenues from the storm cost recovery rider, new revenues from the system hardening rider and higher revenues from the sales and customer mix, which increased the gross margin by approximately $28.7 million;

●

new revenues from the $48.3 million Oklahoma rate increase in which the majority of the annual increase is recovered during the summer months, which increased the gross margin by approximately $21.1 million;

●

new revenues from the Arkansas rate increase, which increased the gross margin by approximately $5.3 million; and

●

new customer growth in the Company’s service territory, which increased the gross margin by approximately $2.8 million.

These increases in the gross margin were partially offset by:

●

milder weather in the Company’s service territory, resulting in an approximate 7.8 percent decrease in cooling degree days in the third quarter of 2009 as compared to the same period in 2008, which decreased the gross margin by approximately $11.2 million; and

●

lower demand and related revenues by non-residential customers in the Company’s service territory, which decreased the gross margin by approximately $6.7 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was approximately $189.5 million during the three months ended September 30, 2009 as compared to approximately $283.4 million during the same period in 2008, a decrease of approximately $93.9 million, or 33.1 percent, primarily due to lower natural gas prices. The Company’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for the Company and its customers. Purchased power costs were approximately $45.8 million during the three months ended September 30, 2009 as compared to approximately $97.5 million during the same period in 2008, a decrease of approximately $51.7 million, or 53.0 percent, primarily due to the termination of the purchase power agreement with the Redbud Facility following the Company’s purchase of the Redbud Facility in September 2008 as well as a decrease in purchases in the energy imbalance service market.

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 fuel adjustment clauses. The 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.

Operating Expenses

Other operation and maintenance expenses were approximately $85.7 million during the three months ended September 30, 2009 as compared to approximately $79.9 million during the same period in 2008, an increase of approximately $5.8 million, or 7.3 percent. The increase in other operation and maintenance expenses was primarily due to:

●

an increase of approximately $2.9 million in salaries and wages expense primarily due to salary increases in 2009;

●

an increase of approximately $2.6 million due to increased spending on vegetation management;

●

an increase of approximately $1.7 million in pension expense in 2009;

●

an increase of approximately $1.2 million in professional services primarily due to the reclassification in 2008, from other operation and maintenance expense to capital costs, of legal expenses related to the acquisition of the Redbud Facility; and

●

an increase of approximately $1.0 million primarily due to the Company’s demand-side management initiatives, which expenses are being recovered through a rider.

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

●

a decrease of approximately $1.3 million in technical and construction services primarily due to the utilization of employees instead of contracting external labor for miscellaneous projects;

●

a decrease of approximately $1.3 million due to lower bad debt expense primarily due to a change in the provision calculation as a result of the Oklahoma rate case whereby the portion of the uncollectible provision related to fuel will be recovered through the fuel adjustment clause beginning in August 2009 and going forward; and

●

a decrease of approximately $1.2 million in fleet transportation expense primarily due to lower fuel costs in 2009.

Depreciation and amortization expense was approximately $47.3 million during the three months ended September 30, 2009 as compared to approximately $37.7 million during the same period in 2008, an increase of approximately $9.6 million, or 25.5 percent, primarily due to additional assets being placed into service, including the Redbud Facility that was placed into service in September 2008, and amortization of several regulatory assets.

Taxes other than income were approximately $16.0 million during the three months ended September 30, 2009 as compared to approximately $14.4 million during the same period in 2008, an increase of approximately $1.6 million, or 11.1 percent, primarily due to an increase in ad valorem taxes.

Additional Information

Interest Income. Interest income was approximately $0.2 million during the three months ended September 30, 2009 as compared to approximately $1.7 million during the same period in 2008, a decrease of approximately $1.5 million, or 88.2 percent, primarily due to interest from customers related to the fuel under recovery balance during the three months ended September 30, 2008.

Allowance for Equity Funds Used During Construction. AEFUDC was approximately $5.5 million during the three months ended September 30, 2009. There was no AEFUDC during the same period in 2008. The increase in AEFUDC was primarily due to construction costs associated with OU Spirit and the extra high voltage transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma being constructed by the Company.

Other Income (Loss). Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $5.9 million during the three months ended September 30, 2009 as compared to a loss of approximately $1.1 million during the same period in 2008, an increase in other income of approximately $7.0 million. Approximately $3.6 million of the increase in other income related to the benefit associated with the tax gross-up of AEFUDC and approximately $2.7 million of the increase in other income was due to more customers participating in the guaranteed flat bill program and lower than expected usage resulting from milder weather during the third quarter of 2009 as compared to the same period in 2008.

Interest Expense. Interest expense was approximately $22.8 million during the three months ended September 30, 2009 as compared to approximately $18.7 million during the same period in 2008, an increase of approximately $4.1 million, or 21.9 percent. The increase in interest expense was primarily due to an increase of approximately $7.4 million in interest expense related to the issuances of long-term debt during the third and fourth quarters of 2008. This increase in interest expense was partially offset by:

●

a decrease of approximately $2.2 million related to interest on short-term debt primarily due to lower short-term borrowings in 2009 due to the issuance of long-term debt by the Company during the third and fourth quarters of 2008; and

●

a decrease of approximately $2.1 million primarily due to a higher allowance for borrowed funds used during construction for capitalized interest.

Income Tax Expense. Income tax expense was approximately $57.5 million during the three months ended September 30, 2009 as compared to approximately $43.8 million during the same period in 2008, an increase of approximately $13.7 million, or 31.3 percent, primarily due to higher pre-tax income in the third quarter of 2009 as compared to the same period in 2008 partially offset by an increase in Federal renewable energy credits and Oklahoma investment tax credits in the third quarter of 2009 as compared to the same period in 2008.

Nine Months Ended September 30, 2009 as Compared to Nine Months Ended September 30, 2008

Operating Income

The Company’s operating income increased approximately $68.9 million during the nine months ended September 30, 2009 as compared to the same period in 2008 primarily due to a higher gross margin and lower operation and maintenance expense partially offset by higher depreciation and amortization expense and higher taxes other than income.

Gross Margin

Gross margin was approximately $744.9 million during the nine months ended September 30, 2009 as compared to approximately $655.4 million during the same period in 2008, an increase of approximately $89.5 million, or 13.7 percent. The gross margin increased primarily due to:

●

increased price variance, which included revenues related to the recovery through rates of the acquisition and operating costs of the Redbud Facility, new revenues from the storm cost recovery rider, new revenues from the system hardening rider and higher revenues from the sales and customer mix, which increased the gross margin by approximately $76.8 million;

●

new revenues from the Arkansas rate increase, which increased the gross margin by approximately $6.4 million;

●

new customer growth in the Company’s service territory, which increased the gross margin by approximately $6.2 million; and

●

increased transmission revenues due to higher transmission volumes and increased rates due to the FERC formula rate tariff filing, which increased the gross margin by approximately $1.2 million.

These increases in gross margin were partially offset by:

●

milder weather in the Company’s service territory, which decreased the gross margin by approximately $12.9 million; and

●

lower demand and related revenues by non-residential customers in the Company’s service territory, which decreased the gross margin by approximately $8.9 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was approximately $467.7 million during the nine months ended September 30, 2009 as compared to approximately $719.6 million during the same period in 2008, a decrease of approximately $251.9 million, or 35.0 percent, primarily due to lower natural gas prices. Purchased power costs were approximately $125.8 million during the nine months ended September 30, 2009 as compared to approximately $214.1 million during the same period in 2008, a decrease of approximately $88.3 million, or 41.2 percent, primarily due to the termination of the purchase power agreement with the Redbud Facility following the Company’s purchase of the Redbud Facility in September 2008 as well as a decrease in purchases in the energy imbalance service market.

Operating Expenses

Other operation and maintenance expenses were approximately $248.9 million during the nine months ended September 30, 2009 as compared to approximately $260.0 million during the same period in 2008, a decrease of approximately $11.1 million, or 4.3 percent. The decrease in other operation and maintenance expenses was primarily due to:

●

a decrease of approximately $9.5 million due to a correction of the over-capitalization of certain payroll, benefits, other employee related costs and overhead costs in previous years in March 2008, as discussed in Note 2 of Notes to Condensed Financial Statements;

●

a decrease of approximately $8.4 million in contract technical and construction services attributable to decreased spending on overhauls at some of the Company’s power plants during the first nine months of 2009 as compared to the same period in 2008 and utilization of employees instead of contracting external labor;

●

a decrease of approximately $3.2 million due to the reclassification of 2006 and 2007 pension settlement costs to a regulatory asset due to the Arkansas rate case settlement, as discussed in Note 1 of Notes to Condensed Financial Statements;

●

an increase in capitalized labor in the first nine months of 2009 as compared to the same period in 2008, which decreased other operation and maintenance expenses by approximately $3.2 million; and

●

a decrease of approximately $3.0 million in fleet transportation expense primarily due to lower fuel costs in 2009.

These decreases in other operation and maintenance expenses were partially offset by:

●

an increase of approximately $6.8 million in salaries and wages expense primarily due to salary increases in 2009;

●

an increase of approximately $3.9 million due to increased spending on vegetation management;

●

an increase of approximately $3.0 million due to the Company’s demand-side management initiatives, which expenses are being recovered through a rider;

●

an increase of approximately $2.1 million in medical and dental expenses; and

●

an increase of approximately $1.1 million due to increased bad debt expense primarily related to higher customer billings coupled with a higher charge-off rate partially offset by a decrease due to a change in the provision calculation as a result of the Oklahoma rate case whereby the portion of the uncollectible provision related to fuel will be recovered through the fuel adjustment clause beginning in August 2009 and going forward.

Depreciation and amortization expense was approximately $138.8 million during the nine months ended September 30, 2009 as compared to approximately $110.9 million during the same period in 2008, an increase of approximately $27.9 million, or 25.2 percent, primarily due to additional assets being placed into service, including the Redbud Facility that was placed into service in September 2008, and amortization of several regulatory assets.

Taxes other than income was approximately $48.4 million during the nine months ended September 30, 2009 as compared to approximately $44.9 million during the same period in 2008, an increase of approximately $3.5 million, or 7.8 percent, primarily due to an increase in ad valorem taxes.

Additional Information

Interest Income. Interest income was approximately $1.0 million during the nine months ended September 30, 2009 as compared to approximately $2.7 million during the same period in 2008, a decrease of approximately $1.7 million, or 63.0 percent, primarily due to interest from customers related to the fuel under recovery balance during the three months ended September 30, 2008.

Allowance for Equity Funds Used During Construction. AEFUDC was approximately $10.7 million during the nine months ended September 30, 2009. There was no AEFUDC during the same period in 2008. The increase in AEFUDC was primarily due to construction costs associated with OU Spirit and the extra high voltage transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma being constructed by the Company.

Other Income. Other income was approximately $14.7 million during the nine months ended September 30, 2009 as compared to approximately $0.7 million during the same period in 2008, an increase of approximately $14.0 million.

Approximately $6.9 million of the increase in other income related to the benefit associated with the tax gross-up of AEFUDC and approximately $6.4 million of the increase in other income was due to more customers participating in the guaranteed flat bill program and lower than expected usage resulting from milder weather during the first nine months of 2009 as compared to the same period in 2008.

Other Expense. Other expense was approximately $2.5 million during the nine months ended September 30, 2009 as compared to approximately $11.5 million during the same period of 2008, a decrease of approximately $9.0 million, or 78.3 percent, primarily due to 2008 write-downs of approximately $7.7 million for deferred costs associated with the cancelled Red Rock power plant and approximately $1.5 million associated with the 2007 and 2006 storm costs.

Interest Expense. Interest expense was approximately $70.3 million during the nine months ended September 30, 2009 as compared to approximately $55.2 million during the same period in 2008, an increase of approximately $15.1 million, or 27.4 percent. The increase in interest expense was primarily due to an increase of approximately $25.8 million in interest expense related to the issuances of long-term debt during the third and fourth quarters of 2008. This increase in interest expense was partially offset by:

●

a decrease of approximately $5.4 million related to interest on short-term debt primarily due to lower short-term borrowings in 2009 due to the issuance of long-term debt by the Company during the third and fourth quarters of 2008;

●

a decrease of approximately $3.5 million due to a higher allowance for borrowed funds used during construction for capitalized interest; and

●

a decrease of approximately $2.4 million due to the settlement of treasury lock agreements the Company entered into related to the issuance of long-term debt by the Company in January 2008.

Income Tax Expense. Income tax expense was approximately $81.2 million during the nine months ended September 30, 2009 as compared to approximately $49.6 million during the same period in 2008, an increase of approximately $31.6 million, or 63.7 percent, primarily due to higher pre-tax income in the first nine months of 2009 as compared to the same period in 2008 partially offset by an increase in Federal renewable energy credits and Oklahoma investment tax credits in the third quarter of 2009 as compared to the same period in 2008.

Financial Condition

The balance of Cash and Cash Equivalents was approximately $50.7 million at December 31, 2008 with no balance at September 30, 2009. See “Cash Flows” for a discussion of the changes in Cash and Cash Equivalents.

The balance of Accounts Receivable was approximately $201.3 million and $172.2 million at September 30, 2009 and December 31, 2008, respectively, an increase of approximately $29.1 million, or 16.9 percent, primarily due to an increase in the Company’s billings related to higher sales volumes and increased rates from the Oklahoma and Arkansas rate increases.

The balance of Fuel Inventories was approximately $87.8 million and $56.6 million at September 30, 2009 and December 31, 2008, respectively, an increase of approximately $31.2 million, or 55.1 percent, primarily due to a higher coal inventory balance due to higher average prices and planned outages at one of the Company’s coal-fired power plants.

The balance of Fuel Clause Under Recoveries was approximately $0.3 million and $24.0 million at September 30, 2009 and December 31, 2008, respectively, a decrease of approximately $23.7 million, or 98.8 percent, primarily due to the fact that the amount billed to retail customers was higher than the Company’s cost of fuel. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow the Company to amortize under and over recovery balances.

The balance of Construction Work in Progress was approximately $452.2 million and $169.1 million at September 30, 2009 and December 31, 2008, respectively, an increase of approximately $283.1 million, primarily due to costs associated with OU Spirit and the extra high voltage transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma being constructed by the Company.

The balance of Accounts Payable – Other was approximately $81.2 million and $105.0 million at September 30, 2009 and December 31, 2008, respectively, a decrease of approximately $23.8 million, or 22.7 percent, primarily due to the timing of outstanding checks clearing the bank at December 31, 2008.

The balance of Fuel Clause Over Recoveries was approximately $176.4 million and $8.6 million at September 30, 2009 and December 31, 2008, respectively, an increase of approximately $167.8 million, primarily due to the fact that the amount billed to retail customers was higher than the Company’s cost of fuel. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel cost when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow the Company to amortize under and over recovery balances. As part of the OCC order in the Company’s Oklahoma rate case, the Company will refund approximately $114.9 million in fuel clause over recoveries to its Oklahoma customers over the next 10 months.

The balance of Accrued Benefit Obligations was approximately $223.3 million and $261.9 million at September 30, 2009 and December 31, 2008, respectively, a decrease of approximately $38.6 million, or 14.7 percent, primarily due to pension plan contributions by OGE Energy in 2009.

The balance of Accumulated Deferred Income Taxes was approximately $801.4 million and $722.8 million at September 30, 2009 and December 31, 2008, respectively, an increase of approximately $78.6 million, or 10.9 percent, primarily due to accelerated bonus tax depreciation which resulted in higher Federal and state deferred tax accruals.

Off-Balance Sheet Arrangements

Except as discussed below, there have been no significant changes in the Company’s off-balance sheet arrangements from those discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (“2008 Form 10-K”).

Railcar Lease Agreement

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities in its electric utility business. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) and permanent financings. See “Future Sources of Financing – Short-Term Debt” for information regarding the Company’s revolving credit agreement and commercial paper.

At September 30, 2009, the Company had less than $0.1 million of cash and cash equivalents. At September 30, 2009, the Company had approximately $377.9 million of net available liquidity under its revolving credit agreement.

Cash Flows

Nine Months Ended September 30 (In millions)	2009			2008
Net cash provided from (used in) operating activities	$	437.5		$	(27.7	)
Net cash used in investing activities		(489.1	)		(700.1	)
Net cash provided from financing activities		0.9			864.5

The increase of approximately $465.2 million in net cash provided from operating activities during the nine months ended September 30, 2009 as compared to the same period in 2008 was primarily due to:

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higher fuel recoveries during the nine months ended September 30, 2009 as compared to the same period in 2008;

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cash received during the nine months ended September 30, 2009 from the implementation of the Redbud Facility rider in the third quarter of 2008;

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cash received during the nine months ended September 30, 2009 from the implementation of the Oklahoma rate increase in August 2009; and

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payments made by the Company in the first quarter of 2008 related to the December 2007 ice storm.

The decrease of approximately $211.0 million in net cash used in investing activities during the nine months ended September 30, 2009 as compared to the same period in 2008 was primarily related to higher levels of capital expenditures in 2008 primarily related to the purchase of the Redbud Facility in September 2008 partially offset by capital expenditures in 2009 related to OU Spirit and the extra high voltage transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma being constructed by the Company.

The decrease of approximately $863.6 million in net cash provided from financing activities during the nine months ended September 30, 2009 as compared to the same period in 2008 primarily related to:

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proceeds received from the issuance of $200 million in long-term debt in January 2008 and $250 million in long-term debt in September 2008;

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a capital contribution from OGE Energy to fund a portion of the purchase of the Redbud Facility in 2008; and

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lower levels of short-term debt during the nine months ended September 30, 2009.

Future Capital Requirements

Capital Expenditures

The Company’s estimates of capital expenditures are approximately: 2009 - $622 million, 2010 - $499 million, 2011 - $512 million, 2012 - $449 million, 2013 - $405 million and 2014 - $335 million. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company’s business) plus capital expenditures for known and committed projects (collectively referred to as the “Base Capital Expenditure Plan”). The table below summarizes the capital expenditures by category:

(In millions)	Total		2009			2010-2011		2012-2013		2014
Base Transmission	$	167	$	43	$	73	$	28	$	23
Base Distribution		1,266		163		452		434		217
Base Generation		276		38		82		103		53
Other		139		12		49		52		26
Total Base Transmission, Distribution, Generation and Other		1,848		256		656		617		319
Known and Committed Projects:
Smart Grid Program		19		6		13		---		---
Sunnyside-Hugo (345 kV)		120		1		81		38		---
Sooner-Rose Hill (345 kV)		68		1		67		---		---
Oklahoma City, OK to Woodward, OK (345 kV)		179		156		23		---		---
System Hardening		35		2		33		---		---
OU Spirit		234		200		34		---		---
Balanced Portfolio 3E Projects		285		---		70		199		16
Other		34		---		34		---		---
Total Known and Committed Projects		974		366		355		237		16
Total (A)	$	2,822	$	622	$	1,011	$	854	$	335

(A) The Base Capital Expenditure Plan above excludes any environmental expenditures associated with Best Available Retrofit Technology (“BART”) requirements due to the uncertainty regarding BART costs (see Note 11 of Notes to Condensed Financial Statements for a further discussion).

Additional capital expenditures beyond those identified in the chart above, including incremental growth opportunities in transmission assets and wind generation assets, will be evaluated based upon their impact upon achieving the Company’s financial objectives.

Pension Plan Funding

Future Sources of Financing

Management expects that cash generated from operations and proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings) will be adequate over the next three years to meet anticipated cash needs. The Company utilizes short-term borrowings (through a combination of bank borrowings, commercial paper and borrowings from OGE Energy) to satisfy temporary working capital needs and as an interim source of financing for capital expenditures until permanent financing is arranged.

Short-Term Debt

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by loans under short-term bank facilities. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at September

30, 2009 or December 31, 2008. At September 30, 2009 and December 31, 2008, the Company had approximately $11.0 million and $17.6 million, respectively, in outstanding advances from OGE Energy. The following table provides information regarding OGE Energy’s and the Company’s revolving credit agreements and available cash at September 30, 2009.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate			Amount			Weighted-Average
Entity	Commitment			Outstanding			Interest Rate		Maturity
OGE Energy		$	596.0		$	308.0		0.43%	December 6, 2012
The Company			389.0			11.1		---%	December 6, 2012
			985.0			319.1		0.43%
Cash			---			N/A		N/A		N/A
Total		$	985.0		$	319.1		0.43%

The Company has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2009 and ending December 31, 2010. See Note 9 of Notes to Condensed Financial Statements for a discussion of OGE Energy’s and the Company’s short-term debt activity.

Expected Issuance of Long-Term Debt

The Company expects to issue between $200 million and $250 million of long-term debt in mid-2010, depending on market conditions, to fund capital expenditures.

Critical Accounting Policies and Estimates

The Condensed Financial Statements and Notes to Condensed Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Condensed Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s Condensed Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the Company’s critical accounting estimates have been discussed with OGE Energy’s Audit Committee and are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s 2008 Form 10-K.

Accounting Pronouncements

See Notes to Condensed Financial Statements for a discussion of accounting principles that are applicable to the Company.

Commitments and Contingencies

Except as disclosed otherwise in this Form 10-Q and the Company’s 2008 Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows. See Notes 11 and 12 of Notes to Condensed Financial Statements in this Form 10-Q and Notes 13 and 14 of Notes to Condensed Financial Statements and Item 3 of Part I of the 2008 Form 10-K for a discussion of the Company’s commitments and contingencies.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Item 4. Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (“CEO”) and chief financial officer (“CFO”), allowing timely decisions regarding required disclosure. 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 CEO and CFO, of the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in the Company’s internal control over financial reporting has occurred during the Company’s most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Part I, Item 3 of the Company’s 2008 Form 10-K for a description of certain legal proceedings presently pending. Except as set forth below and in Notes 11 and 12 of Notes to Condensed Financial Statements in this Form 10-Q, there are no new significant cases to report against the Company and there have been no material changes in the previously reported proceedings.

1. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which have resulted in the under reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal government, some percentage of which Grynberg, as relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

Transok, Inc. and the Company, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006. The defendants filed motions for attorneys’ fees and other legal costs on various bases. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. On November 15, 2006, Grynberg filed appeals with the Tenth Circuit Court of Appeals. On March 17, 2009, the Tenth Circuit Court of Appeals affirmed the October 2006 order of the District Court of Wyoming dismissing the complaints against all gas defendants, including all Company parties. On April 14, 2009, Grynberg filed a petition for rehearing in the Tenth Circuit Court of Appeals. By order dated May 4, 2009, the Tenth Circuit Court denied Grynberg’s request for rehearing. Grynberg filed a petition for writ of certiorari in the U.S. Supreme Court on August 3, 2009. By order dated October 5, 2009, the U.S. Supreme Court denied Grynberg’s petition for writ of certiorari. This ruling concludes the appeal of the October 2006 order of the District Court of Wyoming dismissing complaints against all gas defendants, including all Company parties. The Company now considers this case closed.

2. Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I). On September 24, 1999, various subsidiaries of OGE Energy 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 the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of OGE Energy’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of OGE Energy’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages.

3. Franchise Fee Lawsuit. On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC. In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorized the Company to collect the challenged franchise fee charges. A procedural schedule and notice requirements for the matter were established by the OCC on December 4, 2008. On March 10, 2009, the Oklahoma Attorney General, the Company, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed. A hearing on the motions to dismiss was held before an administrative law judge (“ALJ”) on March 26, 2009. On June 30, 2009, the ALJ issued a report recommending that the application be dismissed. On July 9, 2009, the applicants filed a Notice of Appeal and a hearing on this matter is scheduled for November 5, 2009. The Company believes that this case is without merit.

Item 1A. Risk Factors.

Except as discussed below, there have been no significant changes in the Company’s risk factors from those discussed in the Company’s 2008 Form 10-K.

Costs of compliance with environmental laws and regulations are significant and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations, financial position, or liquidity.

We are subject to extensive Federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife mortality, natural resources and health and safety that could, among other things, restrict or limit the output of certain facilities or the use of certain fuels required for the production of electricity and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.

On March 5, 2009, the U.S. Environmental Protection Agency (“EPA”) initiated rulemaking concerning new national emission standards for hazardous air pollutants for existing reciprocating internal combustion engines by proposing amendments to the National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engine Maximum Achievable Control Technology (“RICE MACT Amendments”). Depending on the final regulations that may be enacted by the EPA for the RICE MACT Amendments, Company facilities will likely be impacted. The costs that may be incurred to comply with these regulations, including the testing and modification of the affected engines, are uncertain at this time. The current proposed compliance deadline is three years from the effective date of the final rules.

There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, air emissions related to our operations and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be able to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary.

requirements will apply to suppliers of fossil fuel and industrial chemicals, manufacturers of motor vehicles and engines, as well as large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain Company facilities. The rule requires the collection of data beginning on January 1, 2010 with the first annual reports due to the EPA on March 31, 2011. Certain reporting requirements included in the initial proposed rules that may have significantly affected capital expenditures were not included in the final reporting rule. Additional requirements have been reserved for further review by the EPA with additional rulemaking possible. The outcome of such review and cost of compliance of any additional requirements is uncertain at this time.

Item 6. Exhibits.

Exhibit No.	Description
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) 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.
99.01	Copy of Settlement Agreement dated July 2, 2009. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed July 6, 2009 (File No. 1-12579) and incorporated by reference herein)
99.02	Copy of OCC Order dated July 24, 2009. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed July 30, 2009 (File No. 1-12579) and incorporated by reference herein)

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/ Scott Forbes
	Scott Forbes
	Controller and Chief Accounting Officer

October 30, 2009

Attached files

OKLAHOMA GAS & ELECTRIC CO Reports

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