OKLAHOMA GAS & ELECTRIC CO - FORM 10-Q

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EX-31.01 - EXHIBIT 31.01 - OKLAHOMA GAS & ELECTRIC CO	ogande3rd10qex3101.htm
EX-32.01 - EXHIBIT 32.01 - OKLAHOMA GAS & ELECTRIC CO	ogande3rd10qex3201.htm
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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, 2010

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 þ 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). þ 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 þ (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 þ

At September 30, 2010, 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, 2010

TABLE OF CONTENTS

		Page

FORWARD-LOOKING STATEMENTS		1


Part I – FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Condensed Statements of Income		2
Condensed Statements of Cash Flows		3
Condensed Balance Sheets		4
Condensed Statements of Changes in Stockholder’s Equity		6
Condensed Statements of Comprehensive Income		6
Notes to Condensed Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		23

Item 3. Quantitative and Qualitative Disclosures About Market Risk		39

Item 4. Controls and Procedures		39


Part II – OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 1A. Risk Factors		41

Item 6. Exhibits		41

Signature		42

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 from those expressed in forward-looking statements. 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, 2009 (“2009 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, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;

the ability of Oklahoma Gas and Electric Company (the “Company”), a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”), and OGE Energy 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 2009 Form 10-K.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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)	2010		2009		2010		2009

OPERATING REVENUES	$	723.0	$	577.9	$	1,679.8	$	1,339.9

COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)		311.2		235.7		792.8		595.0
Gross margin on revenues		411.8		342.2		887.0		744.9

OPERATING EXPENSES
Other operation and maintenance		110.8		85.7		305.9		248.9
Depreciation and amortization		53.1		47.3		153.4		139.1
Taxes other than income		16.9		16.0		51.8		48.4
Total operating expenses		180.8		149.0		511.1		436.4

OPERATING INCOME		231.0		193.2		375.9		308.5

OTHER INCOME (EXPENSE)
Interest income		0.1		0.2		0.1		1.0
Allowance for equity funds used during construction		2.6		5.5		7.2		10.7
Other income (loss)		(1.1)		5.9		2.2		14.7
Other expense		(0.4)		(1.3)		(1.4)		(2.5)
Net other income		1.2		10.3		8.1		23.9

INTEREST EXPENSE
Interest on long-term debt		27.7		24.0		76.9		72.3
Allowance for borrowed funds used during construction		(1.3)		(2.9)		(3.5)		(5.9)
Interest on short-term debt and other interest charges		1.0		1.7		3.4		3.9
Interest expense		27.4		22.8		76.8		70.3

INCOME BEFORE TAXES		204.8		180.7		307.2		262.1

INCOME TAX EXPENSE		62.7		57.5		103.9		81.2

NET INCOME	$	142.1	$	123.2	$	203.3	$	180.9

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)	2010		2009

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	203.3	$	180.9
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation and amortization		153.4		139.1
Deferred income taxes and investment tax credits, net		130.2		89.3
Allowance for equity funds used during construction		(7.2)		(10.7)
Price risk management assets		---		(0.2)
Price risk management liabilities		---		0.2
Regulatory assets		7.4		13.4
Regulatory liabilities		(10.7)		(12.4)
Other assets		10.9		(0.9)
Other liabilities		(51.1)		(48.2)
Change in certain current assets and liabilities
Accounts receivable, net		(76.5)		(29.1)
Accrued unbilled revenues		(11.2)		(12.5)
Fuel, materials and supplies inventories		(4.8)		(36.8)
Gas imbalance assets		0.1		0.4
Fuel clause under recoveries		(0.6)		23.7
Other current assets		4.4		3.0
Accounts payable		5.0		(23.8)
Accounts payable - affiliates		(0.3)		(4.0)
Income taxes payable - affiliates		92.5		(7.4)
Fuel clause over recoveries		(119.5)		167.8
Other current liabilities		19.8		5.7
Net Cash Provided from Operating Activities		345.1		437.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(425.7)		(489.5)
Proceeds from sale of assets		1.0		0.4
Net Cash Used in Investing Activities		(424.7)		(489.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		246.2		0.1
Increase in short-term debt		---		0.8
Dividends paid on common stock		(30.3)		---
Changes in advances with parent		(136.3)		---
Net Cash Provided from Financing Activities		79.6		0.9
NET CHANGE IN CASH AND CASH EQUIVALENTS		---		(50.7)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		---		50.7
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	---	$	---

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS

	September 30,		December 31,
	2010		2009
(In millions)	(Unaudited)

ASSETS
CURRENT ASSETS
Accounts receivable, less reserve of $1.7 and $1.7, respectively	$	222.4	$	145.9
Accrued unbilled revenues		68.4		57.2
Advances to parent		139.8		125.9
Fuel inventories		102.9		101.0
Materials and supplies, at average cost		76.4		73.5
Gas imbalances		---		0.1
Deferred income taxes		29.6		23.8
Fuel clause under recoveries		0.9		0.3
Other		10.8		16.1
Total current assets		651.2		543.8

OTHER PROPERTY AND INVESTMENTS, at cost		2.9		2.9

PROPERTY, PLANT AND EQUIPMENT
In service		6,960.6		6,623.7
Construction work in progress		281.1		259.9
Total property, plant and equipment		7,241.7		6,883.6
Less accumulated depreciation		2,484.6		2,416.0
Net property, plant and equipment		4,757.1		4,467.6

DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets		454.3		448.9
Other		17.2		14.9
Total deferred charges and other assets		471.5		463.8

TOTAL ASSETS	$	5,882.7	$	5,478.1

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,
	2010		2009
(In millions)	(Unaudited)

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	4.3	$	4.6
Accounts payable - other		125.1		137.2
Customer deposits		62.8		60.1
Accrued taxes		44.6		29.1
Accrued interest		24.8		40.4
Accrued compensation		25.0		26.3
Price risk management		1.4		---
Gas imbalances		0.1		---
Fuel clause over recoveries		68.0		187.5
Other		38.7		20.2
Total current liabilities		394.8		505.4

LONG-TERM DEBT		1,790.4		1,541.8

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		217.2		261.0
Deferred income taxes		1,082.4		931.2
Deferred investment tax credits		10.3		13.1
Regulatory liabilities		185.1		168.2
Price risk management		2.6		0.7
Other		34.6		32.4
Total deferred credits and other liabilities		1,532.2		1,406.6

Total liabilities		3,717.4		3,453.8

COMMITMENTS AND CONTINGENCIES (NOTE 10)

STOCKHOLDER’S EQUITY
Common stockholder’s equity		958.4		958.4
Retained earnings		1,209.3		1,066.3
Accumulated other comprehensive loss, net of tax		(2.4)		(0.4)
Total stockholder’s equity		2,165.3		2,024.3

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	5,882.7	$	5,478.1

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)

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

Balance at December 31, 2009	$ 100.9	$ 857.5	$ 1,066.3	$ (0.4)	$ 2,024.3
Comprehensive income (loss)
Net income	---	---	203.3	---	203.3
Other comprehensive loss, net of tax	---	---	---	(2.0)	(2.0)
Comprehensive income (loss)	---	---	203.3	(2.0)	201.3
Dividends declared on common stock	---	---	(60.3)	---	(60.3)
Balance at September 30, 2010	$ 100.9	$ 857.5	$ 1,209.3	$ (2.4)	$ 2,165.3

Balance at December 31, 2008	$ 100.9	$ 857.5	$ 865.9	$ ---	$ 1,824.3
Comprehensive income
Net income	---	---	180.9	---	180.9
Other comprehensive income, net of tax	---	---	---	0.1	0.1
Comprehensive income	---	---	180.9	0.1	181.0
Balance at September 30, 2009	$ 100.9	$ 857.5	$ 1,046.8	$ 0.1	$ 2,005.3

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2010		2009		2010		2009

Net income	$	142.1	$	123.2	$	203.3	$	180.9
Other comprehensive income, net of tax
Deferred commodity contracts hedging gains (losses), net of tax of ($0.5) million, $0.1 million, ($1.3) million and $0.1 million, respectively		(0.8)		0.1		(2.0)		0.1
Other comprehensive income (loss), net of tax		(0.8)		0.1		(2.0)		0.1
Total comprehensive income	$	141.3	$	123.3	$	201.3	$	181.0

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

OKLAHOMA GAS AND ELECTRIC COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

Organization

Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. 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 generally accepted accounting principles (“GAAP”) 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, 2010 and December 31, 2009, the results of its operations for the three and nine months ended September 30, 2010 and 2009 and the results of its cash flows for the nine months ended September 30, 2010 and 2009, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 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, 2009 (“2009 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)	2010		2009
Regulatory Assets
Current
Fuel clause under recoveries	$	0.9	$	0.3
Miscellaneous (A)		0.9		2.2
Total Current Regulatory Assets	$	1.8	$	2.5

Non-Current
Benefit obligations regulatory asset	$	333.0	$	357.8
Income taxes recoverable from customers, net		41.1		19.1
Deferred storm expenses		30.0		28.0
Unamortized loss on reacquired debt		15.6		16.5
Deferred pension plan expenses		14.7		18.1
Smart Grid		10.6		---
Red Rock deferred expenses		7.4		7.7
Miscellaneous		1.9		1.7
Total Non-Current Regulatory Assets	$	454.3	$	448.9

Regulatory Liabilities
Current
Fuel clause over recoveries	$	68.0	$	187.5
Miscellaneous (B)		17.6		7.3
Total Current Regulatory Liabilities	$	85.6	$	194.8

Non-Current
Accrued removal obligations, net	$	179.3	$	168.2
Miscellaneous		5.8		---
Total Non-Current Regulatory Liabilities	$	185.1	$	168.2

(A)	Included in Other Current Assets on the Condensed Balance Sheets.

(B)	Included in Other Current Liabilities on the Condensed Balance Sheets.

For a discussion of regulatory assets related to the Company’s Smart Grid program, see Note 11.

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 adjusted, 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 $27.0 million and $22.9 million during the three months ended September 30, 2010 and 2009, respectively, and $76.8 million and $67.8 million during the nine months ended September 30, 2010 and 2009, 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 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, either as overhead based primarily on labor costs or using 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 each of the three months ended September 30, 2010 and 2009, the Company recorded an expense from its affiliate, Enogex LLC and its subsidiaries (“Enogex”), of $8.7 million for transporting gas to the Company’s natural gas-fired generating facilities. During each of the nine months ended September 30, 2010 and 2009, the Company recorded an expense from Enogex of $26.1 million for transporting gas to the Company’s natural gas-fired generating facilities. During each of the three months ended September 30, 2010 and 2009, the Company recorded an expense from Enogex of $3.2 million for natural gas storage services. During the nine months ended September 30, 2010 and 2009, the Company recorded an expense from

Enogex of $9.5 million and $9.6 million, respectively, for natural gas storage services. During the three months ended September 30, 2010 and 2009, the Company also recorded natural gas purchases from its affiliate, OGE Energy Resources, Inc. (“OERI”) of $16.6 million and $12.4 million, respectively. During the nine months ended September 30, 2010 and 2009, the Company also recorded natural gas purchases from OERI of $42.1 million and $30.8 million, respectively. There are $4.5 million and $4.7 million of natural gas purchases recorded at September 30, 2010 and December 31, 2009, respectively, which 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 long 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 50,000 million British thermal units (“MMBtu”) per month from August 2009 to December 2013 (see Note 3 for a further discussion).

During each of the three and nine months ended September 30, 2010, the Company recorded interest income of $0.1 million from OGE Energy for advances made to OGE Energy from the Company. There was no interest income during the three and nine months ended September 30, 2009.

There was no interest expense during the three months ended September 30, 2010. During the nine months ended September 30, 2010 and each of the three and nine months ended September 30, 2009, the Company recorded interest expense of less than $0.1 million 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, 2010, the Company declared dividends to OGE Energy of $60.3 million. During the nine months ended September 30, 2009, the Company declared no dividends to OGE Energy.

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Statements of Income, Condensed Statement of Cash Flows and Condensed Balance Sheet to conform to the 2010 presentation primarily related to the presentation of regulatory assets and liabilities.

2. Fair Value Measurements

The classification of the Company’s fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs 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).

The Company utilizes the market approach in determining the fair value of its derivative positions by using either the New York Mercantile Exchange (“NYMEX”) published market prices, independent broker pricing data or broker/dealer valuations. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.

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.

At September 30, 2010 and December 31, 2009, the Company had no gross derivative assets measured at fair value on a recurring basis. At September 30, 2010 and December 31, 2009, the Company had $4.0 million and $0.7 million, respectively, of gross derivative liabilities measured at fair value on a recurring basis which are considered level 2 in the fair value hierarchy.

The following table summarizes 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, 2010 and December 31, 2009.

	September 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
(In millions)	Amount		Value		Amount		Value

Price Risk Management Liabilities
Energy Derivative Contracts	$	4.0	$	4.0	$	0.7	$	0.7

Long-Term Debt
Senior Notes	$	1,655.0	$	1,958.1	$	1,406.4	$	1,492.1
Industrial Authority Bonds		135.4		135.4		135.4		135.4

The carrying value of the financial instruments on the Condensed Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s energy derivative contracts was determined generally based on quoted market prices. The valuation of instruments also considers the credit risk of the counterparties. The fair value of the Company’s long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities.

3. 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. Natural gas swaps are used to manage the Company’s natural gas exposure associated with a wholesale generation sales contract.

On July 1, 2009, the Company, Enogex and OERI entered into hedging transactions to offset natural gas long 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 50,000 MMBtu’s per month from August 2009 to December 2013.

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: (i) electric power contracts by the Company and (ii) 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’s exposure to changes in interest rates primarily relates to short-term variable debt and commercial paper. 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. The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce interest expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

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. Forecasted transactions, which are 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.

At September 30, 2010 and December 31, 2009, the Company had no derivative instruments 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, 2010 and December 31, 2009, the Company had no derivative instruments that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

At September 30, 2010 and December 31, 2009, the Company had no material derivative instruments that were not designated as hedging instruments.

Credit-Risk Related Contingent Features in Derivative Instruments

At September 30, 2010, the Company had no derivative instruments that contain credit-risk related contingent features.

4. Stock-Based Compensation

The Company recorded compensation expense of $0.6 million pre-tax ($0.3 million after tax) and $1.4 million pre-tax ($0.9 million after tax), respectively, during the three and nine months ended September 30, 2010 related to the Company’s portion of OGE Energy’s performance units. The Company recorded compensation expense of $0.4 million pre-tax ($0.3 million after tax) and $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 performance units.

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, 2010, there were 22,900 shares and 218,033 shares, respectively, of new common stock issued pursuant to OGE Energy’s compensation plans related to exercised stock options and payouts of earned performance units, of which 5,100 shares and 42,124 shares, respectively, related to the Company’s employees.

There was no restricted stock awarded during the three months ended September 30, 2010. During the nine months ended September 30, 2010, OGE Energy awarded 23,775 shares of restricted stock, of which none related to the Company’s employees. During both the three and nine months ended September 30, 2010, there were 1,684 shares of restricted stock forfeited, of which 546 shares related to the Company’s employees.

5. Accumulated Other Comprehensive Loss

The balance of Accumulated Other Comprehensive Loss was $2.4 million and $0.4 million at September 30, 2010 and December 31, 2009, respectively, related to deferred commodity contracts hedging activity.

6. 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 tax examinations by tax authorities for years prior to 2006 or state and local tax examinations by tax authorities for years prior to 2002. 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. The Company earns both Federal and Oklahoma state tax credits associated with the production from its wind farms 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.

The Company had a Federal tax net operating loss for 2009 primarily caused by the accelerated tax depreciation provisions contained within the American Recovery and Reinvestment Act of 2009 (“ARRA”). ARRA allowed a current deduction for 50 percent of the cost of certain property placed into service during 2009. This tax loss resulted in a $30 million current income tax receivable related to the 2009 tax year. On November 6, 2009, the Worker, Homeownership, and Business Assistance Act of 2009 was signed into law by the President. This new law provided for a five-year carry back of net operating losses incurred in 2008 or 2009. This expanded carryback period enabled the Company to carry back the entire 2009 tax loss. A carryback claim was filed in March 2010 and a refund of $30 million was received by the Company in April 2010.

In June 2010, new legislation was passed in Oklahoma that created a moratorium, from July 1, 2010 through June 30, 2012, on 30 income tax credits. For income tax purposes, credits affected by the moratorium may not be claimed for any event, transaction, investment, expenditure or other act for which the credits would otherwise be allowable. During this two-year window, affected credits generated by the Company will be deferred and utilized at a time after the moratorium expires. For financial accounting purposes, the Company will receive the benefits in the future as the credits do not expire if they are not utilized in the period they are generated.

In September 2010, the Small Business Jobs and Credit Act of 2010 was signed into law, which allows the Company to record a current income tax deduction for 50 percent of the cost of certain property placed into service during 2010 as a result of the accelerated tax depreciation provisions within the new law. As a result, for income tax purposes, the Company expects a Federal tax net operating loss for 2010. For financial accounting purposes, the Company recorded an increase in its Non-Current Deferred Income Taxes Liability at September 30, 2010 on the Company’s Condensed Balance Sheet to recognize the financial statement impact of this new law.

Medicare Part D Subsidy

On March 23, 2010, the Patient Protection and Affordable Care Act of 2009 (the “Patient Protection Act”) was signed into law, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (the “Reconciliation Act” and, together with Patient Protection Act, the “Acts”), which makes various amendments to certain aspects of the Patient Protection Act, was signed into law. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D.

The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”). OGE Energy has been recognizing the federal subsidy since 2005 related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the Medicare Act, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually.

Under the Acts, beginning in 2013 an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in earnings in the period enacted regardless of the effective date. As retiree healthcare liabilities and related tax impacts are already reflected in OGE Energy’s Condensed Consolidated Financial Statements, OGE Energy recognized a one-time, non-cash charge of $11.4 million during the quarter ended March 31, 2010 for the write-off of previously recognized tax benefits relating to Medicare Part D subsidies to reflect the change in the tax treatment of the federal subsidy, of which $7.0 million was the Company’s portion.

7. Long-Term Debt

At September 30, 2010, 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:

SERIES	DATE DUE	AMOUNT
		(In millions)
0.30% - 0.50%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.35% - 0.52%	Muskogee Industrial Authority, January 1, 2025		32.4
0.33% - 0.55%	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. As the Company has both the intent and ability to refinance the Bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the Bonds are classified as long-term debt in the Company’s Condensed Financial Statements. The Company believes that it has sufficient liquidity to meet these obligations.

8. Short-Term Debt and Credit Facility

At September 30, 2010 and December 31, 2009, there were $139.8 million and $125.9 million, respectively, in net outstanding advances to OGE Energy. The Company has an intercompany borrowing agreement with OGE Energy whereby the Company has access to up to $250 million of OGE Energy’s revolving credit amount. This agreement has a termination date of January 9, 2012. At September 30, 2010, there were no intercompany borrowings under this agreement. The Company also has $389.0 million of liquidity under a bank facility which 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, 2010, there was $9.5 million supporting letters of credit at a weighted-average interest rate of 0.14 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at September 30, 2010. At September 30, 2010, the Company had less than $0.1 million in cash and cash equivalents.

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 OGE Energy’s and the Company’s credit facilities could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy’s and the Company’s short-term borrowings, but a reduction in OGE Energy’s and the Company’s credit ratings would not result in any defaults or accelerations. Any future downgrade of the Company could 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.

9. 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)	2010 (A)		2009 (A)		2010 (B)		2009 (B)
Service cost	$	2.5	$	2.9	$	7.5	$	8.7
Interest cost		6.4		6.2		19.1		18.5
Expected return on plan assets		(8.6)		(6.6)		(25.7)		(19.8)
Amortization of net loss		4.4		4.6		13.2		13.9
Amortization of unrecognized prior service cost		0.7		0.2		1.9		0.7
Net periodic benefit cost	$	5.4	$	7.3	$	16.0	$	22.0

	Restoration of Retirement Income Plan
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2010 (A)		2009 (A)		2010 (B)		2009 (B)
Interest cost	$	---	$	---	$	0.1	$	---
Amortization of net loss		---		---		---		0.1
Amortization of unrecognized prior service cost		0.1		---		0.2		0.1
Net periodic benefit cost	$	0.1	$	---	$	0.3	$	0.2

(A)	In addition to the $5.5 million and $7.3 million of net periodic benefit cost recognized during the three months ended September 30, 2010 and 2009, respectively, the Company recognized the following:

an increase in pension expense during the three months ended September 30, 2010 of $2.3 million and a reduction in pension expense of less than $0.1 million during the same period in 2009 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 $16.3 million and $22.2 million of net periodic benefit cost recognized during the nine months ended September 30, 2010 and 2009, respectively, the Company recognized the following:

an increase in pension expense during the nine months ended September 30, 2010 of $5.8 million and a reduction in pension expense of $2.2 million during the same period in 2009 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 $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)	2010		2009		2010		2009
Service cost	$	0.8	$	0.5	$	2.2	$	1.6
Interest cost		3.4		2.9		10.3		8.6
Expected return on plan assets		(1.7)		(1.5)		(5.0)		(4.7)
Amortization of transition obligation		0.6		0.6		1.9		1.9
Amortization of net loss		2.6		0.9		7.7		3.0
Amortization of unrecognized prior service cost		---		0.2		---		0.6
Net periodic benefit cost	$	5.7	$	3.6	$	17.1	$	11.0

Pension Plan Funding

In the third quarter of 2010, OGE Energy contributed $10 million to its pension plan, of which $9.3 million was the Company’s portion, for a total contribution of $50 million to its pension plan during 2010, of which $47.0 million was the Company’s portion. No additional contributions are expected in 2010.

10. Commitments and Contingencies

Except as set forth below and in Note 11, the circumstances set forth in Notes 12 and 13 to the Company’s Financial Statements included in the Company’s 2009 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 September 30, 2010, the Company had a noncancellable operating lease with purchase options, covering 1,462 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 fair 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 $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 expired with respect to 135 railcars on November 2, 2009 and was not replaced. The lease agreement with respect to the remaining 135 railcars expired on March 5, 2010 and is now continuing on a month-to-month basis with a 30-day notice required by either party to terminate the agreement.

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.

Oxley Litigation

The Company has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma. This case has been pending for more than 11 years. The plaintiffs alleged that the Company breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs in amounts set forth in the contracts. The plaintiffs’ most recent Statement of Claim describes $2.7 million in take-or-pay damages (including interest) and $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, the Company agreed to provide the plaintiffs with $5.8 million of consideration and the parties agreed to arbitrate the dispute. The arbitration hearing was completed and the final briefs were provided to the arbitration panel on March 17, 2010. On May 19, 2010, the panel issued an arbitration award in an amount less than the consideration previously paid by the Company and, as a result, the Company did not owe any additional amount. The Company now considers this case closed.

Natural Gas Measurement Case

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 other subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that 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 a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.

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 the Company.

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. 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 authorizes the Company to collect the challenged franchise fee charges. On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the 1994 OCC order which authorized the Company to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether the Company’s collection and remittance of such sales tax should be discontinued prospectively. On April 19, 2010, the OCC issued a final order dismissing with prejudice the applicants’ claims for recovery of previously paid taxes on franchise fees and approving the closing of this matter. On June 10, 2010, the plaintiffs filed a motion in the District Court of Creek County, Oklahoma, asking the court to proceed with the original class action. On July 8, 2010, a hearing in this matter was held and the court granted the plaintiffs motion to lift the stay of discovery previously imposed by the Oklahoma Supreme Court but denied any other specific relief pending further action by the court. On August 4, 2010, the Company filed an application to assume original jurisdiction and a petition for a writ of prohibition with the Oklahoma Supreme Court. On September 13, 2010, the Oklahoma Supreme Court issued a writ prohibiting the District Court judge from proceeding further in this case except to dismiss the case. On September 20, 2010, the plaintiffs filed a motion to reconsider this matter with the Oklahoma Supreme Court. While the Company cannot predict the precise outcome of this lawsuit, based on the information known at this time, the Company believes that this lawsuit will not have a material adverse effect on the Company’s financial position or results of operations.

Environmental Matters

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 draft permits for review on both January 9, 2009 and December 4, 2009. The Company provided comments on the draft permit in September 2010. In addition, the Company filed OPDES permit renewal applications for its Muskogee, Mustang and Horseshoe Lake generating stations on March 4, 2009, April 3, 2009 and October 29, 2009, respectively. The draft permits were reviewed and comments have been submitted to the Oklahoma Department of Environmental Quality. The Company has received final permits for its Horseshoe Lake and Seminole generating stations.

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 11 below, in Item 1 of Part II of this Form 10-Q, in Notes 12 and 13 of Notes to the Company’s Financial Statements included in the Company’s 2009 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.

11. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 13 to the Company’s Financial Statements included in the Company’s 2009 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

Completed Regulatory Matters

Renewable Energy Filing

The Company announced in October 2007 its goal to increase its wind power generation over the following four years from its then current 170 megawatts (“MW”) 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 September 2009, the Company reached agreements with two developers who are to build two new wind farms, totaling 280 MWs, in northwestern Oklahoma. Under the terms of the agreements, CPV Keenan is to build a 150 MW wind farm in Woodward County and Edison Mission Energy is to build a 130 MW facility in Dewey County near Taloga. The agreements are both 20-year power purchase agreements, under which the developers are to build, own and operate the wind generating facilities and the Company will purchase their electric output. On January 5, 2010, the Company received an order from the OCC approving the power purchase agreements and authorizing the Company to recover the costs of the power purchase agreements through the Company’s fuel adjustment clause. The 150 MW wind farm is expected to be in service by the end of 2010 and the 130 MW wind farm is expected to be in service during the second quarter of 2011. The Company will continue to evaluate renewable opportunities to add to its power-generation portfolio in the future.

Windspeed Transmission Line Project

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 (“Windspeed”). The OCC subsequently authorized recovery at a construction cost of up to $218 million, including allowance for funds used during construction (“AFUDC”). At September 30, 2010, the construction costs and AFUDC incurred for the Windspeed transmission line were $210.9 million. The Windspeed transmission line was placed into service on March 31, 2010, with the recovery rider being implemented with the first billing cycle in April 2010.

Long-Term Gas Supply Agreements

On February 26, 2010, the Company filed an application with the OCC requesting a waiver of the competitive bid rules to allow the Company to negotiate desired long-term gas purchase agreements. On May 11, 2010, all parties to this case

signed a settlement agreement in this matter requesting that the OCC issue an order granting a waiver of the competitive bid rules. A hearing on the settlement agreement was held on May 13, 2010 and the OCC issued an order approving the settlement agreement on May 27, 2010. On June 29, 2010, the Company filed a separate application with the OCC seeking approval of four long-term gas purchase agreements, which would provide a 12-year supply of natural gas to the Company and account for 25 percent of its currently projected natural gas fuel supply needs over the same time period. On September 26, 2010, the Company filed a motion with the OCC to dismiss this case. A hearing in this matter was held on October 7, 2010 and the administrative law judge recommended that the case be dismissed without prejudice.

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

On July 20, 2009, the OCC Staff filed an application for a public hearing to review and monitor the Company’s application of the 2008 fuel adjustment clause. On September 18, 2009, the Company responded by filing the necessary information and documents to satisfy the OCC’s minimum filing requirement rules. On May 5, 2010, all parties to this case signed a settlement agreement in this matter, stating that the various charges or credits in the Company’s fuel adjustment clause are based upon the actual prices paid for fuel, purchased power or purchased gas. The parties further stipulated that the charges collected by the Company through its fuel adjustment clause from Oklahoma jurisdictional customers were calculated properly, were mathematically accurate and were collected in accordance with the fuel adjustment clause and all applicable OCC rules and orders for calendar year 2008. A hearing on the settlement agreement was held on May 26, 2010 and the OCC issued an order approving the settlement agreement on June 18, 2010.

Smart Grid Project

In February 2009, the ARRA was enacted into law. 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. 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. 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. On April 21, 2010, the Company and the DOE entered into a definitive agreement with regards to the award.

On March 15, 2010, the Company filed an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant. On July 1, 2010, the OCC approved a settlement among all parties to the proceeding. The key settlement terms were:

Pre-approval for system-wide deployment of smart grid technology and authorization for the Company to begin recovering the costs of the system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement;

The Company’s total project costs eligible for recovery (those costs expended or accrued by the Company prior to the termination of the period authorized by the DOE as eligible for grant funds) shall be capped at $366.4 million (“Smart Grid Cost”), inclusive of the DOE grant award amount. The Smart Grid Cost includes the cost of implementing the Norman, Oklahoma smart grid pilot program previously authorized by the OCC. Under the terms of the settlement, the Smart Grid Cost would be deemed to represent an investment that is fair, just and reasonable and in the public interest and to be prudent and will be recognized in the Company’s 2013 general rate case;

To the extent that the Company’s total expenditure for system-wide deployment of smart grid technology during the eligible period exceeds the Smart Grid Cost, the Company shall be entitled to offer evidence and seek to establish that the excess above the Smart Grid Cost was prudently incurred and any such contention may be addressed in the Company’s 2013 rate case;

Implementation of the recovery rider would commence with the first billing cycle in July 2010;

Continued utilization of a return on equity previously approved by the OCC for other various recovery riders;

The recovery rider shall be designed to collect, on a levelized basis, the revenue requirement associated with the estimated project cost of $357.4 million and shall be subject to a true-up in 2014 after the recovery rider expires, including a true-up for project costs, if any, in excess of $357.4 million but less than the Smart Grid Cost. Any over/under recovery remaining will be passed or credited through the Company’s fuel adjustment clause;

The Company guarantees that customers will receive the benefit of certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider;

Beginning January 1, 2011, the Company shall make available the smart grid web portal to all customers having a smart meter. The Company shall expend funds to educate customers regarding the best use of the information

available on the portal. In addition, the Company shall make available to all customers who do not have internet access the opportunity to receive a monthly home energy report. This report shall be made available, free of charge, to customers eligible for the Company’s Low Income Home Energy Assistance Program and/or Senior Citizen program who are without internet service. The incremental costs for web portal access, education and the providing of home energy reports free of charge are to be accumulated as a regulatory asset in an amount up to $6.9 million and recovered in base rates beginning in 2014;

The stranded costs associated with the Company’s existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning in 2014; and

The Company will file an application with the APSC related to the deployment of smart grid technology by the end of 2010.

Crossroads Wind Project

In February 2010, the Company signed memoranda of understanding for 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind project (“Crossroads”) located in Dewey County, Oklahoma. In April 2010, the Company filed an application with the OCC requesting pre-approval of Crossroads and a rider to recover from Oklahoma customers the costs to construct Crossroads. On July 29, 2010, the OCC approved a settlement among all parties to the proceeding that would allow the Company to build, own and operate the wind farm. The key settlement terms approved by the OCC were:

Authorization for the Company to begin recovering the costs of Crossroads through a rider mechanism that will be effective until new rates are implemented after the Company’s 2013 general rate case;

Continued utilization of a return on equity previously approved by the OCC for other various recovery riders, subject to adjustment in the future to reflect the return on equity authorized in subsequent general rate cases;

The Company’s capital costs for which it is entitled recovery for a 197.8 MW wind farm (“Capped Investment Amount”) are $407.7 million;

To the extent the Company’s total investment in Crossroads exceeds the Capped Investment Amount, the Company shall be entitled to offer evidence and seek to establish that the excess above the Capped Investment Amount was prudently incurred and should be included in the Company’s rate base;

If the three-year rolling average of Crossroads megawatt-hours (“MWH”) of production (including a credit for energy not produced due to curtailments or other events caused by system emergencies, force majeure events, or transmission system issues) falls below 712,844 MWHs, the Company shall file testimony demonstrating the appropriate operation of Crossroads as part of its fuel cost recovery filing; and

The Company has the opportunity to expand Crossroads by an additional 29.7 MWs (12 additional turbines). If the pending Southwest Power Pool (“SPP”) interconnection study concludes on or before September 1, 2010, that these additional turbines can be interconnected at incremental costs below $4.7 million, the costs and associated recovery for these additional turbines shall be included in the Crossroads rider, and the Capped Investment Amount and the three-year rolling average of MWH production will be adjusted to $469.7 million and 819,879 MWHs, respectively.

On July 31, 2010, the SPP released its interconnection study which identified that the incremental interconnection costs associated with the additional 29.7 MWs was $1.2 million. Therefore, the Company chose to expand Crossroads by the additional 29.7 MWs with a total projected cost of the project, including AFUDC, to be $450 million, which is below the Capped Investment Amount of $469.7 million. The Company entered into a turbine supply agreement with Siemens whereby the Company is to acquire 227.5 MWs of wind turbine generation at a cost in excess of $300 million. The Company expects Crossroads to be in service by the end of 2011.

The Company is in the process of entering into an interconnection agreement with the SPP for Crossroads. As part of the multi-study interconnection process, the SPP is conducting a stability study to determine the impact Crossroads will have on the existing transmission system. The stability study will determine under what conditions, if any, that Crossroads can fully interconnect to the existing transmission system or whether Crossroads could be required to have a limited output until additional transmission network upgrades are constructed. At this time, the Company cannot predict the outcome of the stability study. A significant delay in the Company being able to fully interconnect Crossroads to the existing transmission system could delay the in-service date of all or a portion of Crossroads and increase the cost of the project. However, based on current information, the Company does not believe that this stability study will result in an interconnection agreement that will materially affect the feasibility of Crossroads.

OU Spirit Wind Power Project

In connection with the OU Spirit wind farm, in January 2008, the Company filed with the SPP for an interconnection agreement 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 interconnection agreement. On May 29, 2009, the Company executed an interim interconnection agreement, allowing OU Spirit to interconnect to the transmission grid, subject to certain conditions. In connection with the interim interconnection agreement, the Company posted a letter of credit with the SPP of $10.9 million, which was later reduced to $9.9 million in October 2009 and further reduced to $9.2 million in February 2010, 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 interconnection agreement with the FERC on June 29, 2009. On August 27, 2009, the FERC issued an order accepting the interim interconnection agreement, subject to certain conditions, which enables OU Spirit to interconnect into the transmission grid until the final interconnection agreement can be put in place, which is expected by the fourth quarter of 2010. Also, the SPP issued a revised interconnection study in September 2010 and concluded that the Company’s liability should only include non-shared network upgrades which have already been completed. Therefore, on October 1, 2010, the $9.2 million letter of credit was cancelled.

The Company is in the process of negotiating a final interconnection agreement with the SPP. This final interconnection agreement will identify several network upgrades that must be constructed. Such network upgrades are expected to be placed in service by the end of 2014. While the SPP has conducted studies that permit the Company to interconnect OU Spirit prior to the completion of these network upgrades, the SPP will conduct further studies in the event that higher priority projects are placed in service prior to when the network upgrades are completed. These higher priority projects include the 150 MW wind farm which is expected to be in service by the end of 2010 and the 130 MW wind farm which is expected to be in service during the second quarter of 2011, which the Company has entered into power purchase agreements. These further SPP studies may result in OU Spirit’s output being limited from time to time until the network upgrades are completed.

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. On July 21, 2010, the FERC issued an order accepting the Company’s July 2009 triennial market power update and found no change from the previous market-based rate authorizations.

On October 14, 2010, OERI filed with the FERC a Notice of Cancellation of OERI’s market-based rate tariff. OERI does not currently make wholesale sales pursuant to its market-based rate authorization, has not done so in several years and does not anticipate doing so in the foreseeable future. Additionally, OERI has no outstanding transactions under its market-based rate tariff, so no customers will be affected by the filing. OERI also requested a waiver of the prior notice filing requirement to allow termination of its market-based rate tariff effective as of October 13, 2010.

Pending Regulatory Matters

Arkansas OU Spirit Application and Renewable Energy Filing

On August 16, 2010, the Company filed an application with the APSC requesting an order determining (i) that the construction of OU Spirit is prudent and is in the public’s interest, (ii) the Company may begin deferring the Arkansas jurisdictional portion of the OU Spirit costs as a regulatory asset beginning September 1, 2010, (iii) the Company may implement a renewable energy temporary surcharge to recover OU Spirit regulatory asset costs until the implementation of new rate schedules in the next general rate filing and (iv) the Company may recover, through the fuel adjustment clause, the costs of purchasing power under two wind purchase power agreements totaling 280 MWs, which were signed in September 2009, as a result of an RFP issued by the Company in December 2008. The agreements are both 20-year power purchase agreements, under which the developers are to build, own and operate the wind generating facilities and the Company will purchase their electric output. The 150 MW wind farm is expected to be in service by the end of 2010 and the 130 MW wind farm is expected to be in service during the second quarter of 2011. A procedural schedule has not been established in this matter.

2010 Arkansas Rate Case Filing

The Company began developing a rate case filing for the Arkansas jurisdiction in early 2010. In June 2010, the Company filed notice with the APSC of its intent to seek an increase in its electric rates, anticipating a rate case filing no sooner than August 2010. On September 28, 2010, the Company filed its rate case with the APSC requesting a rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines and wind energy, that have been completed since the last rate filing in August 2008, as well as rising operating costs. If approved, the targeted implementation date for new electric rates is expected to be during the third quarter of 2011. A hearing in this matter is scheduled for May 24, 2011.

SPP Cost Tracker

On October 7, 2010, the Company filed an application with the OCC seeking recovery of the Oklahoma jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other transmission owners throughout the SPP that have been allocated to the Company through the FERC-approved transmission rates and (ii) SPP administrative fees. The Company requested authorization to implement a cost tracker in order to recover from its retail customers the third party project costs discussed above and to collect its administrative SPP cost assessment levied under Schedule 1A of the SPP open access transmission tariff (“OATT”), which is currently recovered in base rates. The Company also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give the Company the opportunity to recover such costs that will be paid but not recovered until the cost tracker is made effective. A procedural schedule has not been established in this matter.

FERC Transmission Rate Incentive Filing

On October 12, 2010, the Company submitted to the FERC revised tariff sheets to its OATT and to the SPP OATT to implement two limited transmission rate incentives. If approved by the FERC, the revised tariff sheets will authorize recovery of 100 percent of all prudently incurred construction work in progress in rate base for specific 345 kilovolt (“kV”) Extra High Voltage (“EHV”) transmission projects to be constructed and owned by the Company within the SPP’s region. In addition, if approved by the FERC, the revised tariff sheets will authorize the Company to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond the Company’s control. The Company has requested an effective date of January 1, 2011.

SPP Transmission/Substation Projects

The SPP is a regional transmission organization under the jurisdiction of the FERC that was created to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale prices of electricity. The SPP does not build transmission though the SPP’s tariff contains rules that govern the transmission construction process. Transmission

owners complete the construction and then own, operate and maintain transmission assets within the SPP region. When the SPP Board of Directors approves a project, the transmission provider in the area where the project is needed has the first obligation to build.

There are several studies currently under review at the SPP including the EHV study that focuses on year 2026 and beyond to address issues of regional and interregional importance. The EHV study suggests overlaying the SPP footprint with a 345 kV, 500kV and 765kV transmission system and integrating it with neighboring regional entities. In 2009, the SPP Board of Directors approved a new report that recommended restructuring the SPP’s regional planning processes to focus on the construction of a robust transmission system, large enough in both scale and geography, to provide flexibility to meet the SPP’s future needs. The Company expects to actively participate in the ongoing study, development and transmission growth that may result from the SPP’s plans.

In 2007, the SPP notified the Company to construct 44 miles of new 345 kV transmission line which will originate at the Company’s existing 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 June 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.”

In January 2009, the Company received notification from the SPP to begin construction on 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, 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 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 the Balanced Portfolio 3E projects. Balanced Portfolio 3E includes four projects to be built by the Company and includes: (i) construction of 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 $180 million for the Company, which is expected to be in service by December 2013, (ii) construction of 72 miles of transmission line from the Company’s Woodward District EHV 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 $120 million for the Company, which is expected to be in service by April 2014, (iii) construction of 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 $65 million for the Company, which is expected to be in service by December 2012 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 $15 million for the Company, which is expected to be in service by December 2011. 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 beginning in late 2010 or early 2011. 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.”

On April 27, 2010, the SPP approved, contingent upon approval by the FERC of a regional cost allocation methodology filed with the FERC by the SPP, a set of transmission projects titled “Priority Projects.” The Priority Projects consist of several transmission projects, two of which have been assigned to the Company. The 345 kV projects include: (i) construction of 92 miles of transmission line from the Company’s Woodward District EHV substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at a cost of $180 million for the Company, which is expected to be in service by June 2014 and (ii) construction of 80 miles of transmission line from the Company’s Woodward District EHV substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company (“MKEC”) or another company assigned by MKEC at a cost of $135 million to the Company, which is expected to be in service by December 2014. On June 17, 2010, the FERC approved

the cost allocation filed by the SPP and notices to construct these Priority Projects were issued by the SPP on June 30, 2010. On September 27, 2010, the Company responded to the SPP that the Company will construct the Priority Projects discussed above beginning in June 2012. The capital expenditures related to the Priority 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.”

State Legislative Initiative

House Bill 3028 (“HB 3028”) became effective in May 2010 and established an Oklahoma renewable portfolio standard with a statewide goal of renewable energy capacity (on an installed electric generation capacity basis) of 15 percent by year 2015. HB 3028 also designated natural gas as the preferred fuel for all new fossil fuel electric generation in Oklahoma until year 2020, but provides that the OCC may determine that a fossil fuel other than natural gas is in the best interest of customers. By the year 2012, the Company expects that its installed electric generation capacity basis for wind-powered units will be 10 percent.

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.

Overview

Financial Strategy

OGE Energy’s mission 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. OGE Energy intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business.

Summary of Operating Results

Three Months Ended September 30, 2010 as Compared to Three Months Ended September 30, 2009

The Company reported net income of $142.1 million and $123.2 million, respectively, during the three months ended September 30, 2010 and 2009, an increase of $18.9 million, or 15.3 percent, primarily due to a higher gross margin on revenues (“gross margin”) mainly due to warmer weather in the Company’s service territory, rate increases and riders partially offset by higher other operation and maintenance expense.

Nine Months Ended September 30, 2010 as Compared to Nine Months Ended September 30, 2009

The Company reported net income of $203.3 million and $180.9 million, respectively, during the nine months ended September 30, 2010 and 2009, an increase of $22.4 million, or 12.4 percent, primarily due to a higher gross margin mainly due to rate increases and riders and warmer weather in the Company’s service territory partially offset by higher other operation and maintenance expense and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 6 of Notes to Condensed Financial Statements).

Recent Developments and Regulatory Matters

Smart Grid Project

On July 1, 2010, the OCC approved a settlement with all parties to the OCC consideration of the Company’s application for pre-approval for system-wide deployment of smart grid technology and a recovery rider. The recovery rider was implemented with the first billing cycle in July 2010. For a discussion of the settlement agreement terms related to the Company’s Smart Grid application, see Note 11 of Notes to Condensed Financial Statements.

Crossroads Wind Project

On June 28, 2010, a settlement agreement was reached with all the parties to the OCC consideration of the Company’s application for pre-approval of the 197.8 megawatts (“MW”) of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind project (“Crossroads”) and a recovery rider. On July 29, 2010, the OCC approved a settlement among all parties to the proceeding that would allow the Company to build, own and operate the wind farm. For a discussion of the settlement agreement terms approved by the OCC related to the Company’s Crossroads application, see Note 11 of Notes to Condensed Financial Statements.

The Company is in the process of entering into an interconnection agreement with the Southwest Power Pool (“SPP”) for Crossroads. As part of the multi-study interconnection process, the SPP is conducting a stability study to determine the impact Crossroads will have on the existing transmission system. The stability study will determine under what conditions, if any, that Crossroads can fully interconnect to the existing transmission system or whether Crossroads could be required to have a limited output until additional transmission network upgrades are constructed. At this time, the Company cannot predict the outcome of the stability study. A significant delay in the Company being able to fully interconnect Crossroads to the existing transmission system could delay the in-service date of all or a portion of Crossroads and increase the cost of the project. However, based on current information, the Company does not believe that this stability study will result in an interconnection agreement that will materially affect the feasibility of Crossroads.

Arkansas OU Spirit Application and Renewable Energy Filing

2010 Arkansas Rate Case Filing

2010 Outlook

The Company’s 2010 ongoing earnings guidance is between $207 million and $217 million of net income and is projected to be at the upper end of the earnings range. However, certain key assumptions previously disclosed have changed which are listed below. All other assumptions are unchanged from those included in the earnings guidance in the Company’s

Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”) and the Company’s Form 10-Q for the quarter ended June 30, 2010.

2010 Ongoing Earnings Guidance:

Excludes a one-time, non-cash charge recorded in March 2010 of $7.0 million related to the elimination of the tax deduction for the Medicare Part D subsidy.

Includes a projected increase in 2010 in income tax expense of $1.9 million related to the elimination of the tax deduction for the Medicare Part D subsidy.

Key factors and assumptions that have changed include:

	Previous Guidance	Updated Guidance	Reason for Change in Guidance
Net income	No change	No change	Increase in gross margin experienced as a result of favorable weather during 2010 will be offset by increased operating expenses during 2010 primarily resulting from increased maintenance at some of the Company’s power plants and higher postretirement benefit costs.

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.

Ongoing earnings, which as indicated above excludes the one-time, non-cash charge of $7.0 million associated with the elimination of the tax deduction for the Medicare Part D subsidy as a result of the recent health care legislation, is a non-GAAP financial measure. As the Medicare Part D tax subsidy represents a charge which management believes will not be recurring on a regular basis, management believes that the presentation of Ongoing Earnings provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods. Reconciliation of Ongoing Earnings to generally accepted accounting principles (“GAAP”) net income is provided below.

Reconciliation of projected ongoing earnings to projected GAAP net income

	Twelve Months Ended
(In millions)	December 31, 2010
	Low		High
Ongoing earnings	$	207.0	$	217.0
Medicare Part D tax subsidy		(7.0)		(7.0)
Projected GAAP net income	$	200.0	$	210.0

For a discussion of the reasons for the use of Ongoing Earnings, as well as the limitation as an analytical tool, see “Non-GAAP Financial Measure” below.

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, 2010 as compared to the same periods in 2009 and the Company’s financial position at September 30, 2010. Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 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)	2010		2009		2010		2009
Operating income	$	231.0	$	193.2	$	375.9	$	308.5
Net income	$	142.1	$	123.2	$	203.3	$	180.9

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)	2010		2009		2010			2009
Operating revenues	$	723.0	$	577.9		$	1,679.8	$	1,339.9
Cost of goods sold		311.2		235.7			792.8		595.0
Gross margin on revenues		411.8		342.2			887.0		744.9
Other operation and maintenance		110.8		85.7			305.9		248.9
Depreciation and amortization		53.1		47.3			153.4		139.1
Taxes other than income		16.9		16.0			51.8		48.4
Operating income		231.0		193.2			375.9		308.5
Interest income		0.1		0.2			0.1		1.0
Allowance for equity funds used during construction		2.6		5.5			7.2		10.7
Other income (loss)		(1.1)		5.9			2.2		14.7
Other expense		0.4		1.3			1.4		2.5
Interest expense		27.4		22.8			76.8		70.3
Income tax expense		62.7		57.5			103.9		81.2
Net income	$	142.1	$	123.2		$	203.3	$	180.9
Operating revenues by classification
Residential	$	330.9	$	253.4		$	729.8	$	557.3
Commercial		176.5		144.4			409.5		336.1
Industrial		66.2		52.5			164.5		128.3
Oilfield		49.6		38.4			125.6		100.5
Public authorities and street light		67.8		54.0			157.8		126.8
Sales for resale		19.3		15.3			50.5		40.0
Provision for rate refund		(0.4)		---			(0.4)		(0.6)
System sales revenues		709.9		558.0			1,637.3		1,288.4
Off-system sales revenues (A)		5.8		11.1			19.7		25.6
Other		7.3		8.8			22.8		25.9
Total operating revenues	$	723.0	$	577.9		$	1,679.8	$	1,339.9
MWH (B) sales by classification (in millions)
Residential		3.218		2.712			7.644		6.812
Commercial		1.970		1.773			5.133		4.873
Industrial		1.034		0.967			2.891		2.667
Oilfield		0.800		0.782			2.281		2.182
Public authorities and street light		0.898		0.826			2.324		2.226
Sales for resale		0.397		0.385			1.076		0.985
System sales		8.317		7.445			21.349		19.745
Off-system sales		0.142		0.350			0.481		0.850
Total sales		8.459		7.795			21.830		20.595
Number of customers		782,174		775,863			782,174		775,863
Average cost of energy per KWH (C) – cents
Natural gas		4.546		3.468			4.838		3.497
Coal		1.951		1.886			1.891		1.737
Total fuel		3.084		2.575			3.063		2.394
Total fuel and purchased power		3.407		2.803			3.361		2.677
Degree days (D)
Heating - Actual		7		17			2,305		1,946
Heating - Normal		29		29			2,228		2,228
Cooling - Actual		1,541		1,189			2,286		1,849
Cooling - Normal		1,295		1,295			1,850		1,850
(A) Sales to other utilities and power marketers. (B) Megawatt-hour. (C) Kilowatt-hour. (D) 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, 2010 as Compared to Three Months Ended September 30, 2009

Operating Income

The Company’s operating income increased $37.8 million, or 19.6 percent, during the three months ended September 30, 2010 as compared to the same period in 2009 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense and higher depreciation and amortization expense as discussed below.

Gross Margin

Gross margin was $411.8 million during the three months ended September 30, 2010 as compared to $342.2 million during the same period in 2009, an increase of $69.6 million, or 20.3 percent. The gross margin increased primarily due to:

warmer weather in the Company’s service territory, which increased the gross margin by $33.3 million;

increased price variance, which included revenues from various rate riders, including the Windspeed rider, the OU Spirit rider and the Smart Grid rider, and higher revenues from the sales and customer mix, which increased the gross margin by $25.1 million;

revenues from the Oklahoma rate increase, which increased the gross margin by $5.2 million;

higher demand and related revenues by non-residential customers in the Company’s service territory, which increased the gross margin by $4.5 million; and

new customer growth in the Company’s service territory, which increased the gross margin by $2.9 million.

These increases in the gross margin were partially offset by lower other revenues due to fewer transmission requests from others on the Company’s system, which decreased the gross margin by $1.4 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $241.0 million during the three months ended September 30, 2010 as compared to $189.5 million during the same period in 2009, an increase of $51.5 million, or 27.2 percent, primarily due to higher natural gas prices and increased natural gas generation due to ongoing maintenance at some of the Company’s coal-fired power plants. 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 $69.8 million during the three months ended September 30, 2010 as compared to $45.8 million during the same period in 2009, an increase of $24.0 million, or 52.4 percent, primarily due to an increase in purchases in the energy imbalance service market to meet the Company’s generation load requirements and an increase in short-term power agreements resulting in short-term spot market purchases.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through 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 $110.8 million during the three months ended September 30, 2010 as compared to $85.7 million during the same period in 2009, an increase of $25.1 million, or 29.3 percent. The increase in other operation and maintenance expenses was primarily due to:

an increase of $4.2 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;

an increase of $3.6 million in contract technical and construction services expense and an increase of $1.3 million in materials and supplies expense primarily attributable to increased spending for ongoing maintenance at some of the Company’s power plants in the third quarter of 2010 as compared to the same period in 2009;

an increase of $3.5 million in employee benefits expense primarily due to an increase in postretirement benefits due to an increase in medical costs and changes in actuarial assumptions in 2010;

an increase of $2.8 million in activity costs related to less work being capitalized in the third quarter of 2010;

an increase of $2.4 million in salaries and wages expense primarily due to salary increases in 2010;

an increase of $2.3 million in injuries and damages expense primarily due to increased reserves on claims in the third quarter of 2010;

an increase of $1.8 million in allocations from the holding company; and

an increase of $1.4 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider.

These increases in other operation and maintenance expenses were partially offset by a decrease of $1.4 million in incentive compensation expense primarily due to lower accruals in the third quarter of 2010.

Depreciation and amortization expense was $53.1 million during the three months ended September 30, 2010 as compared to $47.3 million during the same period in 2009, an increase of $5.8 million, or 12.3 percent, primarily due to additional assets being placed into service, including OU Spirit that was placed into service in November and December 2009 and the Windspeed transmission line that was placed into service on March 31, 2010.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction (“AEFUDC”) was $2.6 million during the three months ended September 30, 2010 as compared to $5.5 million during the same period in 2009, a decrease of $2.9 million, or 52.7 percent, primarily due to the completion of OU Spirit in November and December 2009 and the Windspeed transmission line on March 31, 2010.

Other Income (Loss). Other loss was $1.1 million during the three months ended September 30, 2010 as compared to other income of $5.9 million during the same period in 2009, a decrease in other income of $7.0 million. The decrease in other income was primarily due to:

a decrease of $4.8 million due to a decreased level of gains recognized in the guaranteed flat bill program during the third quarter of 2010 from higher than expected usage resulting from warmer weather in addition to more customers participating in the guaranteed flat bill program during the third quarter of 2010; and

a decrease of $1.9 million related to the benefit associated with the tax gross-up of AEFUDC.

Interest Expense. Interest expense was $27.4 million during the three months ended September 30, 2010 as compared to $22.8 million during the same period in 2009, an increase of $4.6 million, or 20.2 percent, primarily due to a $3.7 million increase related to the issuance of $250 million of long-term debt in June 2010 and a $1.6 million increase due to a lower allowance for borrowed funds used during construction during the third quarter of 2010 as compared to the same period in 2009.

Income Tax Expense. Income tax expense was $62.7 million during the three months ended September 30, 2010 as compared to $57.5 million during the same period in 2009, an increase of $5.2 million, or 9.0 percent, primarily due to higher pre-tax income during the three months ended September 30, 2010 as compared to the same period in 2009 partially offset by an increase in Federal renewable energy credits during the three months ended September 30, 2010 as compared to the same period in 2009.

Nine Months Ended September 30, 2010 as Compared to Nine Months Ended September 30, 2009

Operating Income

The Company’s operating income increased $67.4 million, or 21.8 percent, during the nine months ended September 30, 2010 as compared to the same period in 2009 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense and higher taxes other than income as discussed below.

Gross Margin

Gross margin was $887.0 million during the nine months ended September 30, 2010 as compared to $744.9 million during the same period in 2009, an increase of $142.1 million, or 19.1 percent. The gross margin increased primarily due to:

warmer weather in the Company’s service territory, which increased the gross margin by $46.7 million;

revenue from the Oklahoma rate increase, which increased the gross margin by $24.1 million;

new customer growth in the Company’s service territory, which increased the gross margin by $5.9 million;

higher demand and related revenues by non-residential customers in the Company’s service territory, which increased the gross margin by $4.5 million; and

revenues from the Arkansas rate increase, which increased the gross margin by $3.5 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $622.4 million during the nine months ended September 30, 2010 as compared to $467.7 million during the same period in 2009, an increase of $154.7 million, or 33.1 percent, primarily due to higher natural gas prices and increased natural gas generation due to ongoing maintenance at some of the Company’s coal-fired power plants. 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 $168.6 million during the nine months ended September 30, 2010 as compared to $125.8 million during the same period in 2009, an increase of $42.8 million, or 34.0 percent, primarily due to an increase in purchases in the energy imbalance service market to meet the Company’s generation load requirements and an increase in short-term power agreements resulting in short-term spot market purchases.

Operating Expenses

Other operation and maintenance expenses were $305.9 million during the nine months ended September 30, 2010 as compared to $248.9 million during the same period in 2009, an increase of $57.0 million, or 22.9 percent. The increase in other operation and maintenance expenses was primarily due to:

an increase of $15.1 million in contract technical and construction services and an increase of $1.9 million in materials and supplies expense primarily attributable to increased spending for ongoing maintenance at some of the Company’s power plants during the nine months ended September 30, 2010 as compared to the same period in 2009;

an increase of $13.5 million in employee benefits expense primarily due to an increase in postretirement benefits due to an increase in medical costs and changes in actuarial assumptions in 2010, a reclassification in May 2009 of 2006 and 2007 pension settlement costs to a regulatory asset, as prescribed in the Arkansas rate case settlement, and an increase in pension expense due to an increase in the amount deferred as a pension regulatory liability in the Company’s Oklahoma jurisdiction resulting from the Company’s 2009 Oklahoma rate case;

an increase of $7.3 million in salaries and wages expense primarily due to salary increases in 2010;

an increase of $5.4 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;

an increase of $4.0 million in injuries and damages expense primarily due to increased reserves on claims during the nine months ended September 30, 2010;

an increase of $3.8 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider;

an increase of $2.8 million in allocations from the holding company; and

an increase of $1.6 million in overtime expense due to the storms in January and May 2010.

These increases in other operation and maintenance expenses were partially offset by a decrease of $2.0 million in incentive compensation expense primarily due to lower accruals during the nine months ended September 30, 2010.

Depreciation and amortization expense was $153.4 million during the nine months ended September 30, 2010 as compared to $139.1 million during the same period in 2009, an increase of $14.3 million, or 10.3 percent, primarily due to additional assets being placed into service, including OU Spirit that was placed into service in November and December 2009 and the Windspeed transmission line that was placed into service on March 31, 2010.

Additional Information

Allowance for Equity Funds Used During Construction. AEFUDC was $7.2 million during the nine months ended September 30, 2010 as compared to $10.7 million during the same period in 2009, a decrease of $3.5 million or 32.7 percent, primarily due to the completion of OU Spirit in November and December 2009 and the Windspeed transmission line on March 31, 2010.

Other Income. Other income was $2.2 million during the nine months ended September 30, 2010 as compared to $14.7 million during the same period in 2009, a decrease in other income of $12.5 million, or 85.0 percent. The decrease in other income was primarily due to:

a decrease of $9.3 million due to a decreased level of gains recognized in the guaranteed flat bill program during the nine months ended September 30, 2010 from higher than expected usage resulting from warmer weather in addition to more customers participating in the guaranteed flat bill program during the nine months ended September 30, 2010; and

a decrease of $2.4 million related to the benefit associated with the tax gross-up of AEFUDC.

Interest Expense. Interest expense was $76.8 million during the nine months ended September 30, 2010 as compared to $70.3 million during the same period in 2009, an increase of $6.5 million, or 9.2 percent, primarily due to a $4.6 million increase related to the issuance of $250 million of long-term debt in June 2010 and a $2.4 million increase due to a lower allowance for borrowed funds used during construction during the nine months ended September 30, 2010 as compared to the same period in 2009.

Income Tax Expense. Income tax expense was $103.9 million during the nine months ended September 30, 2010 as compared to $81.2 million during the same period in 2009, an increase of $22.7 million, or 28.0 percent, primarily due to:

higher pre-tax income during the nine months ended September 30, 2010 as compared to the same period in 2009;

an adjustment for the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 6 of Notes to Condensed Financial Statements); and

the write-off of previously recognized Oklahoma investment tax credits primarily due to expenditures no longer eligible for the Oklahoma investment tax credit related to the change in the tax method of accounting for capitalization of repair expenditures.

These increases in income tax expense were partially offset by an increase in Federal renewable energy credits during the nine months ended September 30, 2010 as compared to the same period in 2009.

Non-GAAP Financial Measure

The Company has included in this Form 10-Q the non-GAAP financial measure Ongoing Earnings. The Company defines Ongoing Earnings as GAAP net income less the charge for the Medicare Part D tax subsidy. The Medicare Part D tax subsidy represents a charge which management believes will not be recurring on a regular basis. Management believes that the presentation of Ongoing Earnings provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods.

The Company provides a reconciliation of Ongoing Earnings to its most directly comparable financial measure as calculated and presented in accordance with GAAP. The most directly comparable GAAP measure for Ongoing Earnings is GAAP net income which includes the impact of the charge for the Medicare Part D tax subsidy. The non-GAAP financial measure of Ongoing Earnings should not be considered as an alternative to GAAP net income. Ongoing Earnings is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. It should not be considered in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because this non-GAAP financial measure excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of Ongoing Earnings may not be comparable to a similarly titled measure of other companies.

To compensate for the limitations of this non-GAAP financial measure as an analytical tool, the Company believes it is important to review the comparable GAAP measure and understand the differences between the measures.

Reconciliation of Ongoing Earnings to GAAP Net Income for the Nine Months Ended September 30, 2010 and 2009

Nine Months Ended

September 30, 2009

September 30, 2010

Medicare Part D

September 30, 2010

GAAP and Ongoing

(In millions)

Ongoing Earnings

Tax Subsidy

GAAP Net Income

Net Income (A)

The Company

210.3

(7.0)

203.3

180.9

(A) There were no one-time charges for the nine months ended September 30, 2009 therefore, ongoing and GAAP net income are the same.

Financial Condition

The balance of Accounts Receivable was $222.4 million and $145.9 million at September 30, 2010 and December 31, 2009, respectively, an increase of $76.5 million, or 52.4 percent, primarily due to an increase in billings to the Company’s customers reflecting warmer weather in September 2010 as compared to December 2009.

The balance of Construction Work in Progress was $281.1 million and $259.9 million at September 30, 2010 and December 31, 2009, respectively, an increase of $21.2 million, or 8.2 percent, primarily due to increased spending on various distribution, transmission and generation projects, including Crossroads, partially offset by the costs associated with the Windspeed transmission line constructed by the Company which was placed in service on March 31, 2010 being reclassified to Property, Plant and Equipment In Service.

The balance of Accrued Taxes was $44.6 million and $29.1 million at September 30, 2010 and December 31, 2009, respectively, an increase of $15.5 million, or 53.3 percent, primarily due to the timing of ad valorem tax accruals and payments.

The balance of Accrued Interest was $24.8 million and $40.4 million at September 30, 2010 and December 31, 2009, respectively, a decrease of $15.6 million, or 38.6 percent, primarily due to the timing of interest payments on long-term debt in 2010 partially offset by additional interest accrued on long-term debt.

The balance of Fuel Clause Over Recoveries was $68.0 million and $187.5 million at September 30, 2010 and December 31, 2009, respectively, a decrease of $119.5 million, or 63.7 percent, primarily due to the fact that the amount billed to retail customers was lower 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 costs 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 Other Current Liabilities was $38.7 million and $20.2 million at September 30, 2010 and December 31, 2009, respectively, an increase of $18.5 million, or 91.6 percent, primarily due to the over recovery of various rate riders, including the Windspeed rider, the OU Spirit rider and the Smart Grid rider, and an increase in legal accruals.

The balance of Long-Term Debt was $1,790.4 million and $1,541.8 million at September 30, 2010 and December 31, 2009, respectively, an increase of $248.6 million or 16.1 percent, due to the issuance of $250 million of long-term debt in June 2010.

The balance of Accrued Benefit Obligations was $217.2 million and $261.0 million at September 30, 2010 and December 31, 2009, respectively, a decrease of $43.8 million, or 16.8 percent, primarily due to pension plan contributions made by OGE Energy during the second and third quarters of 2010 partially offset by accruals for pension expense.

The balance of Deferred Income Taxes was $1,082.4 million and $931.2 million at September 30, 2010 and December 31, 2009, respectively, an increase of $151.2 million, or 16.2 percent, primarily due to accelerated bonus tax depreciation which resulted in higher Federal and state deferred tax accruals as discussed in Note 6 of Notes to Condensed Financial Statements.

The balance of Regulatory Liabilities was $185.1 million and $168.2 million at September 30, 2010 and December 31, 2009, respectively, an increase of $16.9 million, or 10.0 percent, primarily due to increases related to the removal obligations and Oklahoma pension regulatory liabilities.

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 2009 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.

Net Available Liquidity

At September 30, 2010, the Company had less than $0.1 million of cash and cash equivalents. At September 30, 2010, the Company had $379.5 million of net available liquidity under its revolving credit agreement.

Potential Collateral Requirements

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). While the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also provides for a new regulatory regime for derivatives, including mandatory clearing of certain swaps, exchange trading, margin requirements and other transparency requirements. The Dodd-Frank Act contains provisions that should exempt certain derivatives end-users from much of the clearing requirements. It is unclear whether end-users will be exempt from the margin requirements. The scope of the margin requirements and the end user exemption is uncertain and will be further defined through rulemaking proceedings at the Commodity Futures Trading Commission and the Securities and Exchange Commission. Further, although the Company may qualify for certain exemptions, its derivative counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the new legislation, which may increase the Company’s transaction costs or make it more difficult to enter into hedging transactions on favorable terms. The Company’s inability to enter into hedging transactions on favorable terms, or at all, could increase operating expenses and put the Company at increased exposure to risks of adverse changes in commodities prices. If, as a result of the rulemaking associated with the Dodd-Frank Act, the Company does not qualify for any exemptions related to clearing requirements and/or are subject to margin requirements, the Company would be subject to higher costs and increased collateral requirements. The impact of the provisions of the Dodd-Frank Act on the Company cannot be determined pending issuance of the final implementing regulations.

Cash Flows

	Nine Months Ended
	September 30,
(In millions)	2010		2009
Net cash provided from operating activities	$	345.1	$	437.5
Net cash used in investing activities		(424.7)		(489.1)
Net cash provided from financing activities		79.6		0.9

The decrease of $92.4 million, or 21.1 percent, in net cash provided from operating activities during the nine months ended September 30, 2010 as compared to the same period in 2009 was primarily due to higher fuel refunds during the nine months ended September 30, 2010 as compared to the same period in 2009 partially offset by an income tax refund in February 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repair expenditures and cash received during the nine months ended September 30, 2010 from the implementation of rate increases and riders.

The decrease of $64.4 million, or 13.2 percent, in net cash used in investing activities during the nine months ended September 30, 2010 as compared to the same period in 2009 primarily related to higher levels of capital expenditures in 2009 related to OU Spirit and the Windspeed transmission line constructed by the Company which was placed in service on March 31, 2010.

The increase of $78.7 million in net cash provided from financing activities during the nine months ended September 30, 2010 as compared to the same period in 2009 was primarily due to the Company using the proceeds received from the issuance of $250 million of long-term debt in June 2010 to make payments to OGE Energy partially offset by dividends paid during the nine months ended September 30, 2010.

Future Capital Requirements and Financing Activities

Capital Expenditures

The Company’s estimates of capital expenditures are: 2010 - $625 million, 2011 - $960 million, 2012 - $655 million, 2013 - $625 million, 2014 - $460 million and 2015 - $320 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”). Capital expenditures estimated for the next five years and beyond are as follows:

	Less than
	1 year		1-3 years		3-5 years		More than
(In millions)	(2010)		(2011-2012)		(2013-2014)		5 years		Total
Base Transmission	$	40	$	65	$	50	$	25	$	180
Base Distribution		220		435		420		210		1,285
Base Generation		50		115		100		50		315
Other		30		50		50		25		155
Total Base Transmission, Distribution,
Generation and Other		340		665		620		310		1,935
Known and Committed Projects:
Transmission Projects:
Sunnyside-Hugo (345 kV)		25		160		---		---		185
Sooner-Rose Hill (345 kV)		10		50		---		---		60
Windspeed (345 kV)		25		---		---		---		25
Balanced Portfolio 3E Projects		---		220		160		---		380
SPP Priority Projects (A)		---		70		245		---		315
Total Transmission Projects		60		500		405		---		965
Other Projects:
Smart Grid Program (B)		40		120		60		10		230
Crossroads (C)		160		290		---		---		450
System Hardening		10		20		---		---		30
Other		15		20		---		---		35
Total Other Projects		225		450		60		10		745
Total Known and Committed Projects		285		950		465		10		1,710
Total capital expenditures (D)	$	625	$	1,615	$	1,085	$	320	$	3,645

(A)	On June 30, 2010, the SPP issued notices to construct to the Company to build two 345 kilovolt transmission lines as discussed in Note 11 of Notes to Condensed Financial Statements.

(B)	These capital expenditures are net of the Smart Grid $130 million grant approved by the U.S. Department of Energy.

(C)	These capital expenditures assume the 227.5 MW configuration.

(D)

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. As discussed in “– Environmental Laws and Regulations” below, pursuant to a proposed regional haze agreement the Company has agreed to install low nitrogen oxide (“NOX”) burners and related equipment at the three affected generating stations. Preliminary estimates indicate the cost will be $100 million (plus or minus 30 percent). For further information, see “– Environmental Laws and Regulations” below.

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

Pension Plan Funding

Fuel Refund

As a result of an interim fuel filing which began in July 2010, the Company expects to refund to its customers $100 million of prior fuel over recoveries by December 2010, of which $50 million is expected to be refunded during the fourth quarter of 2010.

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 and to fund future growth opportunities. 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 capital expenditures until permanent financing is arranged.

Short-Term Debt and Credit Facility

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 8 of Notes to Condensed Financial Statements for a discussion of the Company’s short-term debt activity.

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 2009 Form 10-K.

Accounting Pronouncements

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

Commitments and Contingencies

Except as disclosed otherwise in this Form 10-Q and the Company’s 2009 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 10 and 11 of Notes to Condensed Financial Statements in this Form 10-Q and Notes 12 and 13 of Notes to

Condensed Financial Statements and Item 3 of Part I of the 2009 Form 10-K for a discussion of the Company’s commitments and contingencies.

Environmental Laws and Regulations

The activities of the Company are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact the Company’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. These environmental laws and regulations are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s 2009 Form 10-K. Except as set forth below, there have been no material changes to such items.

Air

RICE MACT Amendments

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 (“proposed RICE MACT Amendments”). On March 3, 2010, the EPA published final rules on a portion of its original proposed amendments and established national emission standards for hazardous air pollutants for three types of compression ignition reciprocating internal combustion engines (“2010 CI RICE MACT Amendments”). The 2010 CI RICE MACT Amendments were effective May 3, 2010 and are expected to have an insignificant impact to the Company. The remaining provisions of the proposed RICE MACT Amendments were effective October 19, 2010. The costs that may be incurred to comply with these remaining proposed regulations, including the testing and modification of the spark ignition engines, are uncertain at this time. The current compliance deadline is three years from the effective date of the enacted rules.

Regional Haze

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. These regulations are intended to protect visibility in national parks and wilderness areas (“Class I areas”) throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the regulation. However, Oklahoma’s impact on parks in other states must also be evaluated. Sulfates and nitrate aerosols can lead to the degradation of visibility. The state of Oklahoma joined with eight other central states to address these visibility impacts.

The Company was required to evaluate the installation of BART to address regional haze at sources built between 1962 and 1977. The Oklahoma Department of Environmental Quality (“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 was included in the ODEQ regional haze state implementation plan (“SIP”) submitted to the EPA on February 18, 2010.

Waivers could not be obtained for the BART-eligible units at the Company’s Seminole, Muskogee and Sooner generating stations. The Company submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of NOX controls on all three units. On May 30, 2008, the Company filed BART evaluations for the affected generating units at the Muskogee and Sooner generating stations. 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 the four coal-fired generating units at its Muskogee and Sooner generating stations. The Company did not propose the installation of scrubbers at these 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 more than $1.0 billion) would not be cost-effective. The ODEQ published a draft SIP for public review on November 13, 2009. This draft SIP suggested that scrubbers would be needed to comply with the regional haze regulations, but noted the Company’s cost-effectiveness analysis. Following negotiations with the ODEQ, in February 2010 the Company and the ODEQ entered into an Agreement (“Agreement”) which specifies that BART for reducing NOX emissions at all seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations should be the installation of low NOX burners with overfire air (and flue gas recirculation on two of the affected units) and accompanying emission rate and annual emission tonnage limits. Preliminary estimates based on recent

industry experience and cost projections estimate the total cost of the NOX-related equipment at the three affected generating stations at $100 million (plus or minus 30 percent). After the Company obtains estimates from vendors based on a detailed engineering design, it will have a more firm estimate of the exact cost of the NOX-related equipment subject to changes in the cost of basic materials. Under the Agreement, the specified BART for reducing sulfur dioxide (“SO2”) at the four coal-fired units at the Muskogee and Sooner generating stations would be continued use of low sulfur coal and emission rate and annual emission tonnage limits consistent with such use of low sulfur coal. If the EPA approves Oklahoma’s regional haze SIP, implementation of these BART requirements would be required within five years of the approval.

Under the Agreement, there also would be an alternative compliance obligation in the event that the EPA disapproves the aforementioned BART determination and the underlying conclusion that dry flue gas desulfurization units with Spray Dryer Absorber (“Dry Scrubbers”) are not cost-effective. In such an event, and only after the Company has exhausted all judicial and administrative appeals of the EPA disapproval, the Company would have two options. First, the Company could choose to install Dry Scrubbers (or meet the corresponding SO2 emissions limits associated with Dry Scrubbers) by January 1, 2018. Second, the Company could choose to comply with the regional haze regulations by implementing a fuel switching alternative. This alternative would require the Company to achieve a combined annual SO2 emission limit by December 31, 2026 that is equivalent to: (i) the SO2 emission limits associated with installing and operating Dry Scrubbers on two of the BART-eligible coal-fired units and (ii) being at or below the SO2 emissions that would result from switching the other two coal-fired units to natural gas. If the Company has elected to comply with this alternative and if, prior to January 1, 2022, any of these units is required by any environmental law other than the regional haze rule to install flue gas desulfurization equipment or achieve an SO2 emissions rate lower than 0.10 lbs/Million British thermal unit, and if the Company proceeds to take all necessary steps to comply with such legal requirement, the enforceable emission limits in the operating permits for the affected coal units would be adjusted to reflect the installation of that equipment or the emission rates specified under such legal requirement and the Company would no longer be required to undertake the 2026 emission levels.

The ODEQ included the Agreement in its regional haze SIP that it submitted to the EPA on February 18, 2010. It is anticipated that the EPA will take final action on the SIP for regional haze during the first quarter of 2011. The possible EPA actions range from approval of the regional haze SIP to disapproval of the regional haze SIP combined with the issuance of a Federal implementation plan for regional haze in Oklahoma. The Company cannot predict what action the EPA will take.

Until the EPA takes final action on the regional haze SIP, 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 expenditures for the installation of emission control equipment 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.

Climate Change

There are state, national and international efforts to address possible effects of global climate change and regulate the emission of greenhouse gases including, most significantly, carbon dioxide. In addition, there is litigation against other companies in which the plaintiffs seek to compel either reductions in the future emission of greenhouse gases or compensation for alleged damages resulting from past emissions of greenhouse gases. Congress has considered legislation that, if enacted, could require reductions of greenhouse gas emissions of as much as 83 percent below the baseline 2005 level, perhaps by implementing a cap-and-trade-system. The Federal legislative proposals also generally included renewable energy standards, energy efficiency mandates and other requirements. It is uncertain at this time whether, and in what form, such legislation will ultimately be adopted. The EPA has begun to implement regulations pertaining to greenhouse gases. The EPA has finalized rules that require reporting of greenhouse gases from certain industry and implementation of “best available control technology” for any new or modified source that would increase greenhouse gases above a certain level. The cost of compliance is unknown at this time. 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 for the Company’s facilities to address climate change, this could result in significant additional capital expenditures and compliance costs.

Uncertainty surrounding global climate change and environmental concerns related to new coal-fired generation development is changing the mix of the potential sources of new generation in the region. Adoption of renewable portfolio standards would be expected to increase the region’s reliance on wind generation. An Oklahoma renewable portfolio standard with a statewide goal of renewable energy capacity (on an installed electric generation capacity basis) of 15 percent by year 2015 became effective in May 2010. A federal renewable portfolio standard has not yet been established.

On April 1, 2010, the EPA and the U.S. Department of Transportation’s National Highway Traffic Safety Administration issued a joint rule to establish new greenhouse gas emissions regulations that affect tailpipe standards for model years 2012 – 2016 light-duty vehicles. This rule makes greenhouse gas emissions subject to regulation under the Federal Clean Air Act for stationary sources as well as for mobile sources. As a result, the Company’s facilities may be required to include greenhouse gas emission limits in permits issued pursuant to the Federal Clean Air Act. On June 3, 2010, the EPA published the final rule tailoring the applicability criteria that determine which stationary sources and modification projects become subject to permitting requirements for greenhouse gas (“GHG”) emissions under the Prevention of Significant Deterioration (“PSD”) and Title V programs of the Federal Clean Air Act (“Tailoring Rule”). The Tailoring Rule establishes a two-step process for implementing regulation of GHGs under the PSD and Title V programs. The Tailoring Rule became effective August 2, 2010. The effects of the Tailoring Rule cannot be determined until the EPA publishes guidance regarding how control requirements will be established.

Sulfur Dioxide

The Federal Clean Air Act includes an acid rain program to reduce SO2 emissions. Reductions were obtained through a program of emission (release) allowances issued by the EPA to power plants covered by the acid rain program. Each allowance permits one ton of SO2 to be released from the chimney. Plants may only release as much SO2 as they have allowances. Allowances may be banked and traded or sold nationwide. Beginning in 2000, the Company became subject to more stringent SO2 emission requirements in Phase II of the acid rain program. These lower limits had no significant financial impact due to the Company’s earlier decision to burn low sulfur coal. In 2009, the Company’s SO2 emissions were below the allowable limits.

On June 2, 2010, the EPA released its final rule strengthening the primary, health-based, national ambient air quality standards (“NAAQS”) for SO2. The Final Rule revokes the existing 24-hour and annual standards and establishes a new one-hour standard at a level of 75 parts per billion. The EPA intends to complete attainment designations within two years of promulgation of the revised SO2 standard, which is expected by June 2012. States with areas designated nonattainment in 2012 would need to submit a SIP to the EPA by early 2014 outlining actions that will be taken to meet the standards as expeditiously as possible, but no later than August 2017. The Company will continue to monitor the EPA’s attainment designation activities.

Transport Rule

On July 6, 2010 the EPA proposed a rule (“Transport Rule”) that would require 31 states and the District of Columbia to reduce power plant emissions that contribute to ozone and fine particle pollution in other states. Of the 31 states, 28 states would be required to reduce both annual SO2 and NOX emissions and 26 states, including Oklahoma, would be required to reduce NOX emissions during only the ozone season (May-September) because they contribute to downwind states’ ozone pollution. The Company is reviewing the proposed rule and any potential impact it may have.

Coal Ash

As previously reported in the Company’s 2009 Form 10-K, the EPA had announced that it was considering regulation of coal ash. On June 21, 2010 the EPA published its proposed rules for regulation of coal ash. The proposal includes two options for the disposal of coal ash, one option that treats it as hazardous waste and another option that treats it as non-hazardous waste. The Company is currently reviewing the proposed rules and any potential impact they may have to its operations and may submit written comments to the EPA.

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 2009 Form 10-K for a description of certain legal proceedings presently pending. Except as set forth below and in Notes 10 and 11 of Notes to Condensed Financial Statements in this Form 10-Q, there are no new significant cases to report against the Company and there have been no material changes in the previously reported proceedings.

1. Oxley Litigation. The Company has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma. This case has been pending for more than 11 years. The plaintiffs alleged that the Company breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs in amounts set forth in the contracts. The plaintiffs’ most recent Statement of Claim describes $2.7 million in take-or-pay damages (including interest) and $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, the Company agreed to provide the plaintiffs with $5.8 million of consideration and the parties agreed to arbitrate the dispute. The arbitration hearing was completed and the final briefs were provided to the arbitration panel on March 17, 2010. On May 19, 2010, the panel issued an arbitration award in an amount less than the consideration previously paid by the Company and, as a result, the Company did not owe any additional amount. The Company now considers this case closed.

2. 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. 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 authorizes the Company to collect the challenged franchise fee charges. On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the 1994 OCC order which authorized the Company to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether the Company’s collection and remittance of such sales tax should be discontinued prospectively. On April 19, 2010, the OCC issued a final order dismissing with prejudice the applicants’ claims for recovery of previously paid taxes on franchise fees and approving the closing of this matter. On June 10, 2010, the plaintiffs filed a motion in the District Court of Creek County, Oklahoma, asking the court to proceed with the original class action. On July 8, 2010, a hearing in this matter was held and the court granted the plaintiffs motion to lift the stay of discovery previously imposed by the Oklahoma Supreme Court but denied any other specific relief pending further action by the court. On August 4, 2010, the Company filed an application to assume original jurisdiction and a petition for a writ of prohibition with the Oklahoma Supreme Court. On September 13, 2010, the Oklahoma Supreme Court issued a writ prohibiting the District Court judge from proceeding further in this case except to dismiss the case. On September 20, 2010, the plaintiffs filed a motion to reconsider this matter with the Oklahoma Supreme Court. While the Company cannot predict the precise outcome of this lawsuit, based on the information known at this time, the Company believes that this lawsuit will not have a material adverse effect on the Company’s financial position or results of operations.

3. 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 other subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that 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.

Item 1A. Risk Factors.

There have been no significant changes in the Company’s risk factors from those discussed in the Company’s 2009 Form 10-K, which are incorporated herein by reference.

Item 6. Exhibits.

Exhibit No.		Description
10.01		Credit agreement dated December 6, 2006, by and between the Company, the Lenders thereto, Wachovia Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, and The Royal Bank of Scotland plc, Mizuho Corporate Bank and Union Bank of California, N.A., as Co-Documentation Agents. (Filed as Exhibit 10.03 to OGE Energy’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12579) and incorporated by reference herein)
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.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Schema Document.
101.PRE		XBRL Taxonomy Presentation Linkbase Document.
101.LAB		XBRL Taxonomy Label Linkbase Document.
101.CAL		XBRL Taxonomy Calculation Linkbase Document.
101.DEF		XBRL Definition Linkbase Document.

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 29, 2010

Attached files

OKLAHOMA GAS & ELECTRIC CO Reports

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