OKLAHOMA GAS & ELECTRIC CO - FORM 10-Q

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EX-31.01 - EXHIBIT 31.01 - OKLAHOMA GAS & ELECTRIC CO	okgaselecex31016302011.htm
EX-32.01 - EXHIBIT 32.01 - OKLAHOMA GAS & ELECTRIC CO	okgaselecex32016302011.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 June 30, 2011

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. R Yes £ No

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). R Yes £ 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 R (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 R No

At June 30, 2011, 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.

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OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2011

TABLE OF CONTENTS



	Page

GLOSSARY OF TERMS	ii

FORWARD-LOOKING STATEMENTS	1

Part I – FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Condensed Statements of Income	2
Condensed Statements of Comprehensive Income	3
Condensed Statements of Cash Flows	4
Condensed Balance Sheets	5
Condensed Statements of Changes in Stockholder's Equity	7
Notes to Condensed Financial Statements	8

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3. Quantitative and Qualitative Disclosures About Market Risk	33

Item 4. Controls and Procedures	33

Part II – OTHER INFORMATION

Item 1. Legal Proceedings	33

Item 1A. Risk Factors	34

Item 6. Exhibits	34

Signature	35

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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this Form 10-Q.



Abbreviation	Definition
2010 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2010
APSC	Arkansas Public Service Commission
BART	Best Available Retrofit Technology
Company	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
Crossroads	Company's Crossroads wind project in Dewey County, Oklahoma
Dry Scrubbers	Dry flue gas desulfurization units with Spray Dryer Absorber
Enogex	Enogex Holdings LLC, collectively with its subsidiaries, a majority-owned subsidiary of OGE Energy
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States
NOX	Nitrogen oxide
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
ODEQ	Oklahoma Department of Environmental Quality
OER	OGE Energy Resources LLC, wholly-owned subsidiary of Enogex LLC
Off-system sales	Sales to other utilities and power marketers
OGE Energy	OGE Energy Corp., parent company of the Company
Pension Plan	Qualified defined benefit retirement plan
PRM	Price risk management
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to the Company's customers
Windspeed	Company's transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma

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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 the Company's 2010 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 the Company 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;


•	whether the Company can successfully implement its Smart Grid program to install meters for its customers and integrate the Smart Grid meters with its customer billing and other computer information systems;


•	advances in technology;


•	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 2010 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.

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Part 1.	FINANCIAL INFORMATION


Item 1.	Financial Statements.

OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011			2010			2011			2010
OPERATING REVENUES	$	568.7		$	512.8		$	990.8		$	956.8
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)	254.3			230.8			473.7			481.6
Gross margin on revenues	314.4			282.0			517.1			475.2
OPERATING EXPENSES
Other operation and maintenance	110.2			101.2			216.0			195.1
Depreciation and amortization	52.1			50.6			103.9			100.3
Taxes other than income	18.8			17.2			37.9			34.9
Total operating expenses	181.1			169.0			357.8			330.3
OPERATING INCOME	133.3			113.0			159.3			144.9
OTHER INCOME (EXPENSE)
Interest income	0.1			—			0.2			—
Allowance for equity funds used during construction	5.8			2.3			10.2			4.6
Other income	1.3			0.8			6.3			3.3
Other expense	(0.9		)	(0.4		)	(1.5		)	(1.0		)
Net other income	6.3			2.7			15.2			6.9
INTEREST EXPENSE
Interest on long-term debt	29.1			25.1			56.9			49.2
Allowance for borrowed funds used during construction	(2.9		)	(1.0		)	(5.2		)	(2.2		)
Interest on short-term debt and other interest charges	1.1			1.1			1.7			2.4
Interest expense	27.3			25.2			53.4			49.4
INCOME BEFORE TAXES	112.3			90.5			121.1			102.4
INCOME TAX EXPENSE	33.7			30.5			36.1			41.2
NET INCOME	$	78.6		$	60.0		$	85.0		$	61.2

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2011		2010		2011		2010
Net income	$	78.6	$	60.0	$	85.0	$	61.2
Other comprehensive income (loss), net of tax
Deferred commodity contracts hedging gains (losses), net of tax of
$0, $0, $0.1 million and ($0.9) million, respectively	—		—		0.2		(1.2		)
Other comprehensive income (loss), net of tax	—		—		0.2		(1.2		)
Comprehensive income (loss)	$	78.6	$	60.0	$	85.2	$	60.0

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended
	June 30,
(In millions)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	85.0		$	61.2
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	103.9			100.3
Deferred income taxes and investment tax credits, net	36.1			47.9
Allowance for equity funds used during construction	(10.2		)	(4.6		)
Loss on disposition and abandonment of assets	—			0.1
Stock-based compensation expense	1.6			—
Regulatory assets	6.8			6.8
Regulatory liabilities	3.3			(6.5		)
Other assets	2.9			3.2
Other liabilities	(45.2		)	(40.6		)
Change in certain current assets and liabilities
Accounts receivable, net	(40.2		)	(46.0		)
Accrued unbilled revenues	(39.8		)	(24.4		)
Fuel, materials and supplies inventories	29.3			(22.7		)
Gas imbalance assets	—			0.1
Fuel clause under recoveries	(21.4		)	(0.6		)
Other current assets	2.0			7.5
Accounts payable	(7.9		)	28.9
Accounts payable - affiliates	1.5			2.6
Income taxes payable - parent	—			112.4
Fuel clause over recoveries	(20.6		)	(50.1		)
Other current liabilities	28.9			13.0
Net Cash Provided from Operating Activities	116.0			188.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(393.0		)	(206.3		)
Reimbursement of capital expenditures	21.6			9.6
Proceeds from sale of assets	0.4			0.8
Net Cash Used in Investing Activities	(371.0		)	(195.9		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	246.3			246.2
Capital contribution from OGE Energy	50.0			—
Dividends paid on common stock	—			(30.3		)
Changes in advances with parent	(41.3		)	(208.5		)
Net Cash Provided from Financing Activities	255.0			7.4
NET CHANGE IN CASH AND CASH EQUIVALENTS	—			—
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	—			—
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED BALANCE SHEETS



	June 30,		December 31,
	2011		2010
(In millions)	(Unaudited)
ASSETS
CURRENT ASSETS
Accounts receivable, less reserve of $1.5 and $1.6, respectively	$	182.5	$	142.3
Accrued unbilled revenues	96.6		56.8
Advances to parent	110.1		68.9
Fuel inventories	103.3		134.9
Materials and supplies, at average cost	79.4		77.1
Gas imbalances	0.1		0.1
Deferred income taxes	11.4		10.7
Fuel clause under recoveries	22.4		1.0
Other	18.4		20.4
Total current assets	624.2		512.2
OTHER PROPERTY AND INVESTMENTS, at cost	2.7		2.9
PROPERTY, PLANT AND EQUIPMENT
In service	7,202.3		7,043.6
Construction work in progress	573.9		328.1
Total property, plant and equipment	7,776.2		7,371.7
Less accumulated depreciation	2,546.2		2,494.4
Net property, plant and equipment	5,230.0		4,877.3
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	414.9		489.4
Other	18.7		16.3
Total deferred charges and other assets	433.6		505.7
TOTAL ASSETS	$	6,290.5	$	5,898.1

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED BALANCE SHEETS (Continued)



	June 30,			December 31,
	2011			2010
(In millions)	(Unaudited)
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	5.9		$	4.4
Accounts payable - other	196.7			144.1
Customer deposits	64.2			63.2
Accrued taxes	33.3			31.2
Accrued interest	42.8			41.6
Accrued compensation	27.9			22.2
Price risk management	1.3			1.3
Fuel clause over recoveries	9.3			29.9
Other	59.2			40.3
Total current liabilities	440.6			378.2
LONG-TERM DEBT	2,039.1			1,790.4
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	148.7			259.8
Deferred income taxes	1,091.0			1,055.3
Deferred investment tax credits	7.7			9.4
Regulatory liabilities	215.9			193.1
Price risk management	1.8			2.2
Other	30.7			31.6
Total deferred credits and other liabilities	1,495.8			1,551.4
Total liabilities	3,975.5			3,720.0
COMMITMENTS AND CONTINGENCIES (NOTE 11)
STOCKHOLDER'S EQUITY
Common stockholder's equity	1,010.1			958.4
Retained earnings	1,306.8			1,221.8
Accumulated other comprehensive loss, net of tax	(1.9		)	(2.1		)
Total stockholder's equity	2,315.0			2,178.1
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	6,290.5		$	5,898.1

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

CONDENSED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY

(Unaudited)



			Premium					Accumulated
			on					Other
	Common		Common		Retained			Comprehensive
(In millions)	Stock		Stock		Earnings			Income (Loss)			Total
Balance at December 31, 2010	$	100.9	$	857.5	$	1,221.8		$	(2.1	)	$	2,178.1
Comprehensive income (loss)
Net income	—		—		85.0			—			85.0
Other comprehensive income (loss), net
of tax	—		—		—			0.2			0.2
Comprehensive income (loss)	—		—		85.0			0.2			85.2
Stock-based compensation	—		1.7		—			—			1.7
Capital contribution from OGE Energy	—		50.0		—			—			50.0
Balance at June 30, 2011	$	100.9	$	909.2	$	1,306.8		$	(1.9	)	$	2,315.0

Balance at December 31, 2009	$	100.9	$	857.5	$	1,066.3		$	(0.4	)	$	2,024.3
Comprehensive income (loss)
Net income	—		—		61.2			—			61.2
Other comprehensive income (loss), net
of tax	—		—		—			(1.2		)	(1.2		)
Comprehensive income (loss)	—		—		61.2			(1.2		)	60.0
Dividends declared on common stock	—		—		(30.2		)	—			(30.2		)
Balance at June 30, 2010	$	100.9	$	857.5	$	1,097.3		$	(1.6	)	$	2,054.1

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

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OKLAHOMA GAS AND ELECTRIC COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)


1.	Summary of Significant Accounting Policies

Organization

The Company generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company's operations are subject to regulation by the OCC, the APSC and the FERC. The Company is a wholly-owned subsidiary of 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 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 June 30, 2011 and December 31, 2010, the results of its operations for the three and six months ended June 30, 2011 and 2010 and the results of its cash flows for the six months ended June 30, 2011 and 2010, 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 six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011 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 2010 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.

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



	June 30,		December 31,
(In millions)	2011		2010
Regulatory Assets
Current
Fuel clause under recoveries	$	22.4	$	1.0
Other (A)	10.2		4.9
Total Current Regulatory Assets	$	32.6	$	5.9
Non-Current
Benefit obligations regulatory asset	$	279.7	$	365.5
Income taxes recoverable from customers, net	48.7		43.3
Deferred storm expenses	27.4		28.6
Smart Grid	22.5		14.2
Unamortized loss on reacquired debt	14.8		15.3
Deferred Pension expenses	11.3		13.5
Red Rock deferred expenses	7.0		7.2
Other	3.5		1.8
Total Non-Current Regulatory Assets	$	414.9	$	489.4
Regulatory Liabilities
Current
Fuel clause over recoveries	$	9.3	$	29.9
Other (B)	28.4		20.9
Total Current Regulatory Liabilities	$	37.7	$	50.8
Non-Current
Accrued removal obligations, net	$	200.7	$	184.9
Pension tracker	15.2		8.2
Total Non-Current Regulatory Liabilities	$	215.9	$	193.1


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


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

As discussed in Note 12 in the Company's pension tracker modification filing, on June 23, 2011, a settlement agreement was filed by parties in the case stating that the pension tracker should be modified as proposed by the Company and that the level of retiree medical costs included in base rates will be reviewed and determined in the Company's next rate case. As a result, the Company recorded an increase to its postretirement medical expense during the three months ended June 30, 2011 of $1.7 million to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in Pension tracker in the table above.

Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is 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 $33.4 million and $26.1 million during the three months ended June 30, 2011 and 2010, respectively, and $64.4 million and $49.8 million during the six months ended June 30, 2011 and 2010, 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.

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During each of the three months ended June 30, 2011 and 2010, the Company recorded an expense from its affiliate, Enogex, of $8.7 million for transporting gas to the Company's natural gas-fired generating facilities. During each of the six months ended June 30, 2011 and 2010, the Company recorded an expense from Enogex of $17.4 million for transporting gas to the Company's natural gas-fired generating facilities. During each of the three months ended June 30, 2011 and 2010, the Company recorded an expense from Enogex of $3.2 million for natural gas storage services. During each of the six months ended June 30, 2011 and 2010, the Company recorded an expense from Enogex of $6.4 million for natural gas storage services. During the three months ended June 30, 2011 and 2010, the Company also recorded natural gas purchases from Enogex, through its subsidiary, OER, of $8.9 million and $11.1 million, respectively. During the six months ended June 30, 2011 and 2010, the Company recorded natural gas purchases from Enogex, through its subsidiary, OER, of $21.4 million and $25.5 million, respectively. There are $6.2 million and $4.3 million of natural gas purchases recorded at June 30, 2011 and December 31, 2010, respectively, which are included in Accounts Payable – Affiliates in the Condensed Balance Sheets for these activities.

On July 1, 2009, the Company, Enogex and OER 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. Enogex sold physical natural gas to OER, and the Company entered into an offsetting natural gas swap with OER. These transactions are for 50,000 million British thermal units per month from August 2009 to December 2013 (see Note 4 for a further discussion).

During each of the three and six months ended June 30, 2011 and 2010, the Company recorded interest income of less than $0.1 million for advances made to OGE Energy from the Company.

During each of the three and six months ended June 30, 2011 and 2010, 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 six months ended June 30, 2010, the Company declared dividends to OGE Energy of $30.3 million. There were no dividends declared during the six months ended June 30, 2011.

In June 2011, OGE Energy made a capital contribution to the Company for $50.0 million.

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Statement of Income and Condensed Statement of Cash Flows to conform to the 2011 presentation primarily related to the presentation of regulatory assets and liabilities.


2.	Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board issued "Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs," which reconciled differences between U.S. GAAP and International Financial Reporting Standards and clarified existing disclosure requirements about fair value measurement as set forth in previously issued accounting guidance in this area. The new standard requires additional disclosures relating to the valuation processes used by the Company related to its fair value measurements using significant unobservable inputs (Level 3), as well as the sensitivity of the fair value measurement to the changes in unobservable inputs. The new standard is applicable to all entities that are required or permitted to measure or disclose the fair value of an asset, a liability or an instrument classified in a reporting entity's shareholders' equity in the financial statements. The new standard is effective for interim and annual reporting periods beginning after December 15, 2011, and should be applied prospectively. Early adoption of this new standard is not permitted. The Company plans to adopt this new standard effective January 1, 2012 and will include the required information beginning with the Company's Form 10-Q for the quarter ended March 31, 2012.

In June 2011, the Financial Accounting Standards Board issued "Comprehensive Income: Presentation of Comprehensive Income," which requires that all non-owner changes in stockholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two-statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The new standard is applicable to all entities that report items of comprehensive income in any period presented. The new standard is effective for interim and annual reporting periods beginning after December 15, 2011, and should be applied retrospectively. Early adoption of this new standard is permitted. The Company adopted this new standard effective June 30, 2011 and has presented in this Form 10-Q its Condensed Statements of Comprehensive Income after its Condensed Statements of Income.

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3.	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. Instruments classified as Level 2 include 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.

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 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 June 30, 2011 and December 31, 2010, the Company had no gross derivative assets measured at fair value on a recurring basis. At June 30, 2011 and December 31, 2010, the Company had $3.1 million and $3.5 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 PRM activities, at June 30, 2011 and December 31, 2010.



	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
(In millions)	Amount		Value		Amount		Value
Price Risk Management Liabilities
Energy Derivative Contracts	$	3.1	$	3.1	$	3.5	$	3.5
Long-Term Debt
Senior Notes	$	1,903.7	$	2,115.4	$	1,655.0	$	1,831.5
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.

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4.	Derivative Instruments and Hedging Activities

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

Commodity Price Risk

The Company occasionally uses commodity price swap contracts to manage the Company's commodity price risk exposures. Natural gas swaps are used to manage the Company's natural gas exposure associated with a wholesale generation sales contract.

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-rate debt and commercial paper. The Company manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. 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 June 30, 2011 and December 31, 2010, the only derivative instruments that were designated as cash flow hedges were the related party natural gas swaps with OER discussed above.

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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 June 30, 2011 and December 31, 2010, 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 June 30, 2011 and December 31, 2010, the Company had no material derivative instruments that were not designated as hedging instruments.

Credit-Risk Related Contingent Features in Derivative Instruments

At June 30, 2011, the Company had no derivative instruments that contain credit-risk related contingent features.


5.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the three and six months ended June 30, 2011 and 2010 related to the Company's portion of OGE Energy's performance units and restricted stock.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2011		2010		2011		2010
Performance units
Total shareholder return	$	0.4	$	0.3	$	0.8	$	0.7
Earnings per share	0.2		0.1		0.7		0.2
Total performance units	0.6		0.4		1.5		0.9
Restricted stock	0.1		0.1		0.1		0.1
Total compensation expense	$	0.7	0.5		$	1.6	$	1.0
Income tax benefit	$	0.3	0.2		$	0.6	$	0.4

The following table summarizes the activity of the Company's stock-based compensation during the three months ended June 30, 2011.



	Units/Shares	Units/Shares
	Related to	Related to
	OGE Energy	the Company	Fair Value
Grants
Restricted stock	829	521	$50.61

OGE Energy issues new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During the three and six months ended June 30, 2011, there were 1,829 shares and 267,045 shares, respectively, of new common stock issued pursuant to OGE Energy's stock incentive plans related to exercised stock options, restricted stock grants and payouts of earned performance units, of which 1,521 shares and 55,301 shares, respectively, related to the Company's employees. During the three and six months ended June 30, 2011, there were 2,660 shares of restricted stock returned to the Company to satisfy tax liabilities, of which none related to the Company's employees.


6.	Accumulated Other Comprehensive Loss

The balance of Accumulated Other Comprehensive Loss was $1.9 million and $2.1 million at June 30, 2011 and December 31, 2010, respectively, related to deferred commodity contracts hedging activity.

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7.	Income Taxes

The Company is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2007 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.


8.	Long-Term Debt

At June 30, 2011, the Company was in compliance with all of its debt agreements.

The Company has tax-exempt pollution control 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)
0.25% - 0.44%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.23% - 0.44%	Muskogee Industrial Authority, January 1, 2025	32.4
0.35% - 0.50%	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.

On May 18, 2011, the OCC issued an order granting the Company authority to issue up to $1 billion in long-term debt securities.

Issuance of New Long-Term Debt

On May 24, 2011, the Company issued $250 million of 5.25% senior notes due May 15, 2041. The proceeds from the issuance were added to the Company's general funds and were used to repay short-term debt. The Company expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.


9.	Short-Term Debt and Credit Facility

At June 30, 2011 and December 31, 2010, there were $110.1 million and $68.9 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, 2013. At June 30, 2011, 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 June 30, 2011, there was $2.2 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 June 30, 2011. At June 30, 2011, the Company had less than $0.1 million in cash and cash equivalents.

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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.

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, 2011 and ending December 31, 2012.


10.	Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of the Company's portion of OGE Energy's 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						Six Months Ended
	June 30,						June 30,
(In millions)	2011 (A)			2010 (A)			2011 (B)			2010 (B)
Service cost	$	2.7		$	2.4		$	5.4		$	5.0
Interest cost	6.5			6.6			13.1			12.7
Expected return on plan assets	(9.4		)	(8.5		)	(18.7		)	(17.1		)
Amortization of net loss	3.9			4.9			7.8			8.8
Amortization of unrecognized prior service cost	0.7			0.6			1.3			1.2
Net periodic benefit cost	$	4.4		$	6.0		$	8.9		$	10.6



	Restoration of Retirement Income Plan
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2011 (A)		2010 (A)		2011 (B)		2010 (B)
Interest cost	$	0.1	$	0.1	$	0.1	$	0.1
Amortization of unrecognized prior service cost	—		—		0.1		0.1
Net periodic benefit cost	$	0.1	$	0.1	$	0.2	$	0.2

(A)

In addition to the $4.5 million and $6.1 million of net periodic benefit cost recognized during the three months ended June 30, 2011 and 2010, respectively, the Company recognized an increase in pension expense during the three months ended June 30, 2011 and 2010 of $2.8 million and $1.5 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Pension tracker (see Note 1).

(B)

In addition to the $9.1 million and $10.8 million of net periodic benefit cost recognized during the six months ended June 30, 2011 and 2010, respectively, the Company recognized an increase in pension expense during the six months ended June 30, 2011 and 2010 of $5.3 million and $2.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Pension tracker (see Note 1).

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	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011 (C)			2010			2011 (C)			2010
Service cost	$	0.5		$	0.6		$	1.1		$	1.4
Interest cost	2.5			3.5			5.0			6.9
Expected return on plan assets	(1.2		)	(1.6		)	(2.4		)	(3.3		)
Amortization of transition obligation	0.7			0.7			1.3			1.3
Amortization of net loss	3.8			2.8			7.7			5.1
Amortization of unrecognized prior service cost	(3.4		)	—			(6.8		)	—
Net periodic benefit cost	$	2.9		$	6.0		$	5.9		$	11.4

(C) In addition to the $2.9 million and $5.9 million of net periodic benefit cost recognized during the three and six months ended June 30, 2011, respectively, the Company recognized an increase in postretirement medical expense during each of the three and six months ended June 30, 2011 of $1.7 million to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are identified as Pension tracker (see Note 1).

Pension Plan Funding

OGE Energy previously disclosed in its 2010 Form 10-K that it may contribute up to $50 million to its Pension Plan during 2011, of which $47 million is expected to be the Company's portion. During the six months ended June 30, 2011, OGE Energy contributed $40 million to its Pension Plan, of which $37.7 million was the Company's portion. OGE Energy currently expects to contribute an additional $10 million during the remainder of 2011. Any remaining expected contributions to its Pension Plan during 2011 would be discretionary contributions, anticipated to be in the form of cash, and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.


11.	Commitments and Contingencies

Except as set forth below and in Note 12, the circumstances set forth in Notes 12 and 13 to the Company's Financial Statements included in the Company's 2010 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Railcar Lease Agreement

The Company has a noncancellable operating lease with purchase options, covering 1,446 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. On December 15, 2010, the Company renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, 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 $23.7 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 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.

Wind Power Purchase Commitment

As previously disclosed, the Company received approval on January 5, 2010 from the OCC for a wind power purchase agreement with a wind developer who was to build a new 130 megawatt wind farm in Dewey County near Taloga in northwestern Oklahoma. This wind farm went in service during July 2011. The agreement is a 20-year power purchase agreement, under which the developer will own and operate the wind generating facility and the Company will purchase its electric output.

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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 GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Financial Statements. Except as otherwise stated above, in Note 12 below, in Item 1 of Part II of this Form 10-Q, in Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I of the Company's 2010 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.


12.	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 2010 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

Completed Regulatory Matters

Wholesale Agreement

On May 28, 2009, the Company sent a termination notice to the Arkansas Valley Electric Cooperative that the Company would terminate its wholesale power agreement to all points of delivery where the Company sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011. In December 2010, the Company and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby the Company will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015. On January 3, 2011, the Company submitted this agreement to the FERC for approval. The FERC approved the new wholesale power agreement on March 2, 2011 and the new contract was effective May 1, 2011. The Arkansas Valley Electric Cooperative contract contributed $17.4 million, or 1.5 percent, to the Company's gross margin for the year ended December 31, 2010. The new Arkansas Valley Electric Cooperative contract is expected to add approximately $4.0 million in additional gross margin from May through December 2011 over the prior contract.

Long-Term Gas Supply Agreements

In May 2010, the OCC approved the Company's request for a waiver of the competitive bid rules to allow the Company to negotiate desired long-term gas purchase agreements. 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. On July 5, 2011, the Company received an order from the OCC dismissing the case without prejudice.

Crossroads Wind Project

As previously disclosed, on July 29, 2010, the Company received an order from the OCC authorizing the Company to recover from Oklahoma customers the cost to construct Crossroads, with the rider being implemented as the individual turbines are placed in service, which is expected by the end of 2011. As part of this project, on June 16, 2011, the Company entered into an interconnection agreement with the SPP for Crossroads which will allow Crossroads to interconnect at the anticipated 227.5 megawatts.

2010 Arkansas Rate Case Filing

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$8.8 million annually; (ii) authorization for the Company to recover the actual cost of third-party transmission charges and SPP administrative fees through a rider mechanism which will remain in effect until new rates are implemented after the Company's next general rate case (the Arkansas jurisdictional portion of the combined costs is expected to be $1.0 million in 2011); and (iii) the deferral of certain expenses associated with a customer education program in an amount not to exceed $0.3 million per year for a maximum of two years.

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 non-Company 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, 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. On February 8, 2011, all parties signed a settlement agreement in this matter which would allow the Company to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. The Company anticipates recovering $1.8 million of incremental revenues in 2011 through the rider. Rather than including the costs of the SPP administrative fee assessment in the recovery rider, the stipulating parties agreed to allow the Company to include the projected 2012 level of the SPP administrative fee assessment in its anticipated Oklahoma rate case to be filed in the summer of 2011. The settlement agreement also stated that in the Company's 2011 Oklahoma general rate case filing, The Company would propose that recovery in base rates for the costs of transmission projects it constructs and owns and that are authorized by the SPP in its regional planning processes should be limited to the Oklahoma retail jurisdictional share of the costs for such projects allocated to the Company by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.

FERC Transmission Rate Incentive Filing

On February 18, 2011, the Company submitted to the FERC a request seeking limited transmission rate incentives for five transmission projects. This February 18, 2011 request is in addition to the October 12, 2010 request described in the Company's 2010 Form 10-K. The Company requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five 345 kilovolt Extra High Voltage transmission projects to be constructed and owned by the Company within the SPP's region. The Company also requested 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. On April 19, 2011, the FERC granted these incentives for the Sooner-Rose Hill, Sunnyside-Hugo and Balanced Portfolio 3E transmission projects discussed in Note 13 of the Company's 2010 Form 10-K.

Demand and Energy Efficiency Program Filing

To build on the success of its earlier programs and further promote energy efficiency and conservation for each class of Company customers, on March 15, 2011, the Company filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting. In seeking approval of these programs, the Company also sought recovery of the program and related costs through a rider that would be added to customers' electric bills. On June 30, 2011, the APSC issued an order approving the Company's energy efficiency plan for 2011 and approving the Company's energy efficiency cost recovery rider for 2011. In Arkansas, the Company's program is expected to cost $7.0 million over a three-year period and is expected to increase the average residential electric bill by $1.47 per month.

FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation

On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid in a particular region, along with the corresponding process for allocating the costs of such expansions. The revised regulations apply only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which are expected to be filed during the third quarter of 2012. Order No. 1000 leaves to individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.

The new rule requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider

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transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, the final rule establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.

On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any federal "right of first refusal" for the incumbent transmission owner (such as the Company) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, the final rule is not intended to affect the right of an incumbent transmission owner (such as the Company) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. The final rule also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP currently has a "right-of-first" refusal for incumbent transmission owners and this provision has played a role in the Company being selected by the SPP to build various transmission projects in Oklahoma.

The Company is continuing to evaluate Order No. 1000 and cannot at this time determine its precise impact on the Company. Nevertheless, at the present time, the Company has no reason to believe that the implementation of Order No. 1000 will impact the Company's transmission projects currently under development and construction for which the Company has received a notice to proceed from the SPP.

Smart Grid Project

As previously reported in the Company's 2010 Form 10-K, on December 17, 2010, the Company filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant awarded by the U.S. Department of Energy under the American Recovery and Reinvestment Act of 2009. On June 22, 2011, the Company reached a settlement agreement with all the parties to the APSC consideration of the Company's December 2010 application for pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant. The Company and the other parties in this matter agreed to ask the APSC to approve the settlement agreement including the following: (i) pre-approval of system-wide deployment of smart grid technology in Arkansas and authorization for the Company to begin recovering the prudently incurred costs of the Arkansas system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement; (ii) cost recovery through the rider would commence when all of the smart meters to be deployed in Arkansas are in service; (iii) the Company guarantees that customers will receive certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider; and (iv) 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 after an order is issued in the Company's next general rate case. The Company currently expects to spend $14 million, net of funds from the U.S. Department of Energy grant, in capital expenditures to implement smart grid in Arkansas pursuant to the settlement agreement. On August 3, 2011, the APSC issued an order in this matter approving the settlement agreement.

Pending Regulatory Matters

Review of the Company's Fuel Adjustment Clause for Calendar Year 2009

On October 29, 2010, the OCC Staff filed an application for a public hearing to review and monitor the Company's application of the 2009 fuel adjustment clause. On December 28, 2010, the Company responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. An intervenor representing a group of the Company's industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by the Company to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing natural gas supply agreement between the Company and Enogex. The Company filed rebuttal testimony on April 4, 2011 in opposition to the claims of the intervenor. Hearings in this matter were held in June and July 2011. Another hearing in this matter is scheduled for August 11, 2011.

Pension Tracker Modification Filing

On February 22, 2011, the Company filed an application with the OCC requesting that the Company's pension tracker be modified to include the difference between the level of retiree medical costs authorized in the Company's last rate case and the current level of these expenses as a regulatory liability, effective January 1, 2011. On June 23, 2011, a settlement agreement was filed by parties in the case stating that the pension tracker should be modified as proposed by the Company and that the level of

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retiree medical costs included in base rates will be reviewed and determined in the Company's next rate case. A hearing in this matter was held on July 14, 2011. The Company expects to receive a decision from the OCC during the third quarter of 2011.

2011 Oklahoma Rate Case Filing

As part of the Joint Stipulation and Settlement Agreement reached in the Company's 2009 Oklahoma rate case filing, the parties agreed that the Company would file a rate case on or before June 30, 2011. On May 27, 2011, the Company requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, the Company filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. The Company is requesting a return on equity of 11.00 percent based on a common equity percentage of 53 percent. Each 0.10 percent change in the requested return on equity affects the requested rate increase by $3.0 million. In its application, the Company seeks to recover increases in its operating costs and to begin earning on approximately $500 million of new capital investments made on behalf of its Oklahoma customers during the previous two and one-half years. The case is expected to proceed through the second half of 2011. The Company expects to receive an order from the OCC in early 2012.


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

Introduction

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 natural gas midstream business. OGE Energy intends to maintain the majority of its assets in the regulated utility business, however, OGE Energy anticipates significant growth opportunities for its natural gas midstream business.

Summary of Operating Results

Three Months Ended June 30, 2011 as Compared to Three Months Ended June 30, 2010

The Company reported net income of $78.6 million and $60.0 million, respectively, during the three months ended June 30, 2011 and 2010 an increase of $18.6 million, or 31.0 percent, primarily due to a higher gross margin from warmer weather in the Company's service territory and the implementation of rate riders in addition to higher allowance for equity funds used during construction partially offset by higher operation and maintenance expense, higher interest expense and higher income tax expense.

Six Months Ended June 30, 2011 as Compared to Six Months Ended June 30, 2010

The Company reported net income of $85.0 million and $61.2 million, respectively, during the six months ended June 30, 2011 and 2010, an increase of $23.8 million, or 38.9 percent, primarily due to a higher gross margin from the implementation of rate riders and warmer weather in the Company's service territory, higher allowance for equity funds used during construction and lower income tax expense related to the elimination of the tax deduction for the Medicare Part D subsidy (as previously reported in the Company's Form 10-Q for the quarter ended March 31, 2011) partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense and higher interest expense.

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Recent Developments and Regulatory Matters

2010 Arkansas Rate Case Filing

On September 28, 2010, the Company filed a 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, that have been completed since the last rate filing in August 2008, as well as increased operating costs. The Company also sought recovery, through a rider, of the Arkansas 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 non-Company transmission owners throughout the SPP that have been allocated to the Company through the FERC-approved transmission rates and (ii) SPP administrative fees. On June 17, 2011, the APSC approved a settlement agreement among all parties to the case and the Company implemented new electric rates effective June 20, 2011. Key items of the APSC order include: (i) the recovery of and a return on significant electric system expansions and upgrades, including high-voltage transmission lines, as well as increased operating costs, totaling $8.8 million annually; (ii) authorization for the Company to recover the actual cost of third-party transmission charges and SPP administrative fees through a rider mechanism which will remain in effect until new rates are implemented after the Company's next general rate case (the Arkansas jurisdictional portion of the combined costs is expected to be $1.0 million in 2011); and (iii) the deferral of certain expenses associated with a customer education program in an amount not to exceed $0.3 million per year for a maximum of two years.

Smart Grid Project

2011 Oklahoma Rate Case Filing

2011 Outlook

OGE Energy currently projects that the Company will exceed the top end of its previously disclosed 2011 earnings guidance of between $209 million and $219 million. The primary driver for the increase is a higher gross margin at the Company from the extremely hot summer weather experienced in its service territory thus far in 2011. With the exception of the warmer weather experienced through July 31, 2011, the key factors and assumptions regarding the Company's 2011 earnings guidance remain unchanged and are contained in the Company's 2010 Form 10-K and the Company's Form 10-Q for the quarter ended

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March 31, 2011. These assumptions include normal weather in the Company's service territory for the remainder of the year.

Results of Operations

The following discussion and analysis presents factors that affected the Company's results of operations for the three and six months ended June 30, 2011 as compared to the same period in 2010 and the Company's financial position at June 30, 2011. Due to seasonal fluctuations and other factors, the operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011 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				Six Months Ended
	June 30,				June 30,
(In millions)	2011		2010		2011		2010
Operating income	$	133.3	$	113.0	$	159.3	$	144.9
Net income	$	78.6	$	60.0	$	85.0	$	61.2

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.

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Dollars in millions)	2011			2010			2011			2010
Operating revenues	$	568.7		$	512.8		$	990.8		$	956.8
Cost of goods sold	254.3			230.8			473.7			481.6
Gross margin on revenues	314.4			282.0			517.1			475.2
Other operation and maintenance	110.2			101.2			216.0			195.1
Depreciation and amortization	52.1			50.6			103.9			100.3
Taxes other than income	18.8			17.2			37.9			34.9
Operating income	133.3			113.0			159.3			144.9
Interest income	0.1			—			0.2			—
Allowance for equity funds used during construction	5.8			2.3			10.2			4.6
Other income	1.3			0.8			6.3			3.3
Other expense	(0.9		)	(0.4		)	(1.5		)	(1.0		)
Interest expense	27.3			25.2			53.4			49.4
Income tax expense	33.7			30.5			36.1			41.2
Net income	$	78.6		$	60.0		$	85.0		$	61.2
Operating revenues by classification
Residential	$	234.4		$	207.7		$	411.2		$	398.9
Commercial	141.9			132.0			240.1			233.0
Industrial	55.9			52.8			100.0			98.3
Oilfield	42.7			40.4			77.6			76.0
Public authorities and street light	55.0			50.5			93.3			90.0
Sales for resale	14.9			14.5			28.1			31.2
System sales revenues	544.8			497.9			950.3			927.4
Off-system sales revenues	12.5			7.5			21.9			13.9
Other	11.4			7.4			18.6			15.5
Total operating revenues	$	568.7		$	512.8		$	990.8		$	956.8
MWH (A) sales by classification (In millions)
Residential	2.3			2.0			4.5			4.4
Commercial	1.8			1.8			3.3			3.2
Industrial	1.0			1.0			1.9			1.9
Oilfield	0.8			0.8			1.6			1.5
Public authorities and street light	0.8			0.7			1.5			1.4
Sales for resale	0.4			0.4			0.7			0.7
System sales	7.1			6.7			13.5			13.1
Off-system sales	0.3			0.2			0.6			0.3
Total sales	7.4			6.9			14.1			13.4
Number of customers	786,125			779,359			786,125			779,359
Average cost of energy per KWH (B) - cents
Natural gas	4.485			4.503			4.477			5.050
Coal	2.032			1.916			2.033			1.858
Total fuel	2.986			2.832			2.842			3.049
Total fuel and purchased power	3.255			3.127			3.156			3.334
Degree days (C)
Heating - Actual	174			158			2,078			2,298
Heating - Normal	236			236			2,199			2,199
Cooling - Actual	885			737			926			745
Cooling - Normal	547			547			555			555


(A)	Megawatt-hour


(B)	Kilowatt-hour

(C)

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

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Three Months Ended June 30, 2011 as Compared to Three Months Ended June 30, 2010

Operating Income

The Company's operating income increased $20.3 million, or 18.0 percent, during the three months ended June 30, 2011 as compared to the same period in 2010 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense as discussed below.

Gross Margin

Gross margin was $314.4 million during the three months ended June 30, 2011 as compared to $282.0 million during the same period in 2010, an increase of $32.4 million, or 11.5 percent. The gross margin increased primarily due to:


•	warmer weather in the Company's service territory, which increased the gross margin by $18.1 million;


•	increased price variance, which included revenues from various rate riders, including the Oklahoma demand program rider, the Smart Grid rider and the system hardening rider, and higher revenues from sales and customer mix, which increased the gross margin by $5.6 million;


•	higher transmission revenue primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction, which increased the gross margin by $4.0 million; and


•	new customer growth in the Company's service territory, 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 $205.3 million during the three months ended June 30, 2011 as compared to $182.8 million during the same period in 2010, an increase of $22.5 million, or 12.3 percent, primarily due to higher natural gas generation and higher coal prices. The Company's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for the Company and its customers. Purchased power costs were $47.1 million during both the three months ended June 30, 2011 and 2010.

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 $110.2 million during the three months ended June 30, 2011 as compared to $101.2 million during the same period in 2010, an increase of $9.0 million, or 8.9 percent. The increase in other operation and maintenance expenses was primarily due to:


•	an increase of $6.0 million in payroll and benefits expense and contract professional services allocated from the holding company;


•	an increase of $2.5 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;


•	an increase of $1.6 million in incentive compensation expense;


•	an increase of $1.4 million in activity costs related to less work being capitalized during the three months ended June 30, 2011; and


•	an increase of $1.3 million in overtime expense primarily due to storms in April 2011.

These increases in other operation and maintenance expenses were partially offset by a decrease of $3.9 million in postretirement benefits expense related to amendments to the Company's retiree medical plan adopted in January 2011 (as previously reported in the Company's Form 10-Q for the quarter ended March 31, 2011) partially offset by a modification to the Company's pension tracker.

Taxes other than income were $18.8 million during the three months ended June 30, 2011 as compared to $17.2 million during the same period in 2010, an increase of $1.6 million, or 9.3 percent, primarily due to higher ad valorem taxes.

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Additional Information

Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $5.8 million during the three months ended June 30, 2011 as compared to $2.3 million during the same period in 2010, an increase of $3.5 million, primarily due to construction costs for Crossroads.

Other Income. Other income was $1.3 million during the three months ended June 30, 2011 as compared to $0.8 million during the same period in 2010, an increase of $0.5 million, or 62.5 percent. The increase in other income was primarily due to an increase of $2.2 million related to the benefit associated with the tax gross-up of allowance for equity funds used during construction partially offset by a decrease of $1.7 million due to a decreased level of gains recognized in the guaranteed flat bill program during the three months ended June 30, 2011 from higher than expected usage resulting from warmer weather.

Interest Expense. Interest expense was $27.3 million during the three months ended June 30, 2011 as compared to $25.2 million during the same period in 2010, an increase of $2.1 million, or 8.3 percent, primarily due to a $4.0 million increase related to the issuance of long-term debt in June 2010 and May 2011 partially offset by a $1.8 million decrease in interest expense due to a higher allowance for borrowed funds used during construction primarily due to construction costs for Crossroads during the three months ended June 30, 2011 as compared to the same period in 2010.

Income Tax Expense. Income tax expense was $33.7 million during the three months ended June 30, 2011 as compared to $30.5 million during the same period in 2010, an increase of $3.2 million, or 10.5 percent. The increase in income tax expense was primarily due to higher pre-tax income during the three months ended June 30, 2011 as compared to the same period in 2010 partially offset by:


•	the write-off of previously recognized Oklahoma investment tax credits during the three months ended June 30, 2010 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; and


•	higher Oklahoma investment tax credits during the three months ended June 30, 2011 as compared to the same period in 2010.

Six Months Ended June 30, 2011 as Compared to Six Months Ended June 30, 2010

Operating Income

The Company's operating income increased $14.4 million, or 9.9 percent, during the six months ended June 30, 2011 as compared to the same period in 2010 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense, as discussed below.

Gross Margin

Gross margin was $517.1 million during the six months ended June 30, 2011 as compared to $475.2 million during the same period in 2010, an increase of $41.9 million, or 8.8 percent. The gross margin increased primarily due to:


•	increased price variance, which included revenues from various rate riders, including the Windspeed transmission line rider, the Oklahoma demand program rider, the Smart Grid rider, the system hardening rider, the Oklahoma storm recovery rider and the OU Spirit rider, and higher revenues from sales and customer mix, which increased the gross margin by $16.9 million;


•	warmer weather in the Company's service territory, which increased the gross margin by $14.7 million;


•	new customer growth in the Company's service territory, which increased the gross margin by $5.0 million;


•	higher demand and related revenues by non-residential customers in the Company's service territory, which increased the gross margin by $3.1 million; and


•	higher transmission revenue primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction, which increased the gross margin by $3.0 million.

These increases in the gross margin were partially offset by lower other revenues due to lower SO2 allowance sales, which decreased the gross margin by $1.7 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $376.4 million during the six months ended June 30, 2011 as compared to $381.4 million during the

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same period in 2010, a decrease of $5.0 million, or 1.3 percent, primarily due to lower natural gas prices and lower natural gas generation partially offset by higher coal prices and higher coal generation. 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 $93.5 million during the six months ended June 30, 2011 as compared to $98.8 million during the same period in 2010, a decrease of $5.3 million, or 5.4 percent, primarily due to a decrease in purchases in the energy imbalance service market and a decrease in cogeneration costs due to maintenance at one of the cogeneration plants during the six months ended June 30, 2011 partially offset by an increase in short-term power purchases.

Operating Expenses

Other operation and maintenance expenses were $216.0 million during the six months ended June 30, 2011 as compared to $195.1 million during the same period in 2010, an increase of $20.9 million, or 10.7 percent. The increase in other operation and maintenance expenses was primarily due to:


•	an increase of $9.8 million in payroll and benefits expense and contract professional services allocated from the holding company;


•	an increase of $6.3 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;


•	an increase of $4.4 million in activity costs related to less work being capitalized during the six months ended June 30, 2011;


•	an increase of $1.1 million in contract technical and construction services expense and an increase of $0.8 million in materials and supplies expense primarily attributable to increased spending for ongoing maintenance at some of the Company's power plants;


•	an increase of $1.8 million in incentive compensation expense;


•	an increase of $1.3 million in salaries and wages expense primarily due to salary increases in 2011; and


•	an increase of $1.2 million in uncollectible expense.

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


•	a decrease of $3.7 million in postretirement benefits expense related to amendments to the Company's retiree medical plan adopted in January 2011 (as previously reported in the Company's Form 10-Q for the quarter ended March 31, 2011) partially offset by a modification to the Company's pension tracker; and


•	a decrease of $1.9 million in injuries and damages expense primarily due to lower reserves on claims during the six months ended June 30, 2011.

Taxes other than income were $37.9 million during the six months ended June 30, 2011 as compared to $34.9 million during the same period in 2010, an increase of $3.0 million, or 8.6 percent, primarily due to higher ad valorem taxes.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for equity funds used during construction was $10.2 million during the six months ended June 30, 2011 as compared to $4.6 million during the same period in 2010, an increase of $5.6 million, primarily due to construction costs for Crossroads partially offset by the completion of the Windspeed transmission line on March 31, 2010.

Other Income. Other income was $6.3 million during the six months ended June 30, 2011 as compared to $3.3 million during the same period in 2010, an increase of $3.0 million, or 90.9 percent, primarily due to an increase of $3.6 million related to the benefit associated with the tax gross-up of allowance for equity funds used during construction partially offset by a decrease of $0.6 million due to a decreased level of gains recognized in the guaranteed flat bill program during the six months ended June 30, 2011 from higher than expected usage resulting from warmer weather.

Interest Expense. Interest expense was $53.4 million during the six months ended June 30, 2011 as compared to $49.4 million during the same period in 2010, an increase of $4.0 million, or 8.1 percent, primarily due to a $7.7 million increase related to the issuance of long-term debt in June 2010 and May 2011. This increase in interest expense was partially offset by:


•	a $3.0 million decrease in interest expense due to a higher allowance for borrowed funds used during construction primarily due to construction costs for Crossroads partially offset by the completion of the Windspeed transmission line on March 31, 2010; and


•	a $1.0 million decrease in interest expense during the six months ended June 30, 2011 due to interest to customers

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related to the fuel over recovery balance.

Income Tax Expense. Income tax expense was $36.1 million during the six months ended June 30, 2011 as compared to $41.2 million during the same period in 2010, a decrease of $5.1 million, or 12.4 percent, primarily due to:


•	the one-time, non-cash charge during the three months ended March 31, 2010 for the elimination of the tax deduction for the Medicare Part D subsidy;


•	the write-off of previously recognized Oklahoma investment tax credits during the six months ended June 30, 2010 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; and


•	higher Oklahoma investment tax credits during the six months ended June 30, 2011 as compared to the same period in 2010.

These decreases in income tax expense were partially offset by higher pre-tax income during the six months ended June 30, 2011 as compared to the same period in 2010.

Financial Condition

The balance of Accounts Receivable was $182.5 million and $142.3 million at June 30, 2011 and December 31, 2010, respectively, an increase of $40.2 million, or 28.3 percent, primarily due to an increase in billings to the Company's customers reflecting warmer weather in June 2011 as compared to December 2010 primarily due to higher usage by the Company's customers and higher seasonal electric rates.

The balance of Accrued Unbilled Revenues was $96.6 million and $56.8 million at June 30, 2011 and December 31, 2010, respectively, an increase of $39.8 million, or 70.1 percent, primarily due to higher usage by the Company's customers and higher seasonal electric rates.

The balance of Advances to Parent was $110.1 million and $68.9 million at June 30, 2011 and December 31, 2010, respectively, an increase of $41.2 million, or 59.8 percent, primarily due to proceeds received from issuance of long-term debt in May 2011 partially offset by payments for various transmission projects and Crossroads, bond interest and other operational needs.

The balance of Fuel Inventories was $103.3 million and $134.9 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $31.6 million, or 23.4 percent, primarily due to lower coal inventory balances due to lower volumes.

The balance of Fuel Clause Under Recoveries was $22.4 million and $1.0 million at June 30, 2011 and December 31, 2010, respectively, an increase of $21.4 million, 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 Construction Work in Progress was $573.9 million and $328.1 million at June 30, 2011 and December 31, 2010, respectively, an increase of $245.8 million, or 74.9 percent, primarily due to increased spending on various transmission projects and Crossroads.

The balance of Regulatory Assets was $414.9 million and $489.4 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $74.5 million, or 15.2 percent, primarily due to amendments to OGE Energy's retiree medical plan adopted in January 2011 (as previously reported in the Company's Form 10-Q for the quarter ended March 31, 2011).

The balance of Accounts Payable - Other was $196.7 million and $144.1 million at June 30, 2011 and December 31, 2010, respectively, an increase of $52.6 million, or 36.5 percent, primarily due to accruals for Crossroads in June 2011.

The balance of Fuel Clause Over Recoveries was $9.3 million and $29.9 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $20.6 million, or 68.9 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.

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The balance of Other Current Liabilities was $59.2 million and $40.3 million at June 30, 2011 and December 31, 2010, respectively, an increase of $18.9 million, or 46.9 percent, primarily due to an increased credit to customers for the off-system sales credit and the over recovery of various rate riders, primarily the Smart Grid rider.

The balance of Long-Term Debt was $2,039.1 million and $1,790.4 million at June 30, 2011 and December 31, 2010, respectively, an increase of $248.7 million, or 13.9 percent, due to the issuance of $250 million of long-term debt in May 2011.

The balance of Accrued Benefit Obligations was $148.7 million and $259.8 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $111.1 million, or 42.8 percent, primarily due to amendments to OGE Energy's retiree medical plan adopted in January 2011 (as previously reported in the Company's Form 10-Q for the quarter ended March 31, 2011) and Pension Plan contributions during the six months ended June 30, 2011 partially offset by accruals for pension and postretirement benefits expense.

The balance of Regulatory Liabilities was $215.9 million and $193.1 million at June 30, 2011 and December 31, 2010, respectively, an increase of $$22.8 million, or 11.8 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 2010 Form 10-K.

Railcar Lease Agreement

Liquidity and Capital Resources

Cash Flows



	Six Months Ended
	June 30,
(In millions)	2011			2010
Net cash provided from operating activities	$	116.0		$	188.5
Net cash used in investing activities	(371.0		)	(195.9		)
Net cash provided from financing activities	255.0			7.4

The decrease of $72.5 million, or 38.5 percent, in net cash provided from operating activities during the six months ended June 30, 2011 as compared to the same period in 2010 was primarily due to income tax refunds received during the six months ended June 30, 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 accelerated tax bonus depreciation partially offset by lower fuel refunds during the six months ended June 30, 2011 as compared to the same period in 2010 and cash received during the six months ended June 30, 2011 from the implementation of rate riders.

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The increase of $175.1 million, or 89.4 percent, in net cash used in investing activities during the six months ended June 30, 2011 as compared to the same period in 2010 primarily related to higher levels of capital expenditures during the six months ended June 30, 2011 related to various transmission projects and Crossroads partially offset by capital expenditures in 2010 related to the Windspeed transmission line.

The increase of $247.6 million in net cash provided from financing activities during the six months ended June 30, 2011 as compared to the same period in 2010 was primarily due to the Company funding capital projects.

Future Capital Requirements and Financing Activities

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, 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.

Capital Expenditures

The Company’s estimates of capital expenditures for the years 2011 through 2016 are shown in the following table. 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.



(In millions)	2011		2012		2013		2014		2015		2016
Base Transmission	$	50	$	50	$	40	$	40	$	40	$	40
Base Distribution	215		200		200		200		200		200
Base Generation	105		80		70		70		70		70
Other	35		30		30		30		30		30
Total Base Transmission, Distribution,
Generation and Other	405		360		340		340		340		340
Known and Committed Projects:
Transmission Projects:
Sunnyside-Hugo (345 kilovolt)	105		30		—		—		—		—
Sooner-Rose Hill (345 kilovolt)	30		5		—		—		—		—
Balanced Portfolio 3E Projects	55		150		190		55		—		—
SPP Priority Projects	5		45		180		95		—		—
Total Transmission Projects	195		230		370		150		—		—
Other Projects:
Smart Grid Program (A)	75		60		25		25		10		10
Crossroads	235		35		—		—		—		—
System Hardening	20		—		—		—		—		—
Total Other Projects	330		95		25		25		10		10
Total Known and Committed Projects	525		325		395		175		10		10
Total (B)	$	930	$	685	$	735	$	515	$	350	$	350


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

(B)

The capital expenditures above exclude any environmental expenditures associated with BART requirements due to the uncertainty regarding BART costs. As discussed in "– Environmental Laws and Regulations" below, pursuant to the Oklahoma SIP and the proposed Federal implementation plan, the Company would be expected to install low NOX burners and related equipment at the three affected generating stations. Preliminary estimates indicate the cost will be between $70 million and $130 million. The proposed Federal implementation plan rejects portions of the Oklahoma SIP with respect to SO2 emissions and, if adopted as proposed, could result in a significant increase in capital expenditures to reduce SO2 emissions. 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.

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Pension Plan Funding

OGE Energy previously disclosed in its 2010 Form 10-K that it may contribute up to $50.0 million to its Pension Plan during 2011, of which $47 million is expected to be the Company's portion. During the six months ended June 30, 2011, OGE Energy contributed $40.0 million to its Pension Plan, of which $37.7 million was the Company's portion. OGE Energy currently expects to contribute an additional $10.0 million during the remainder of 2011. Any remaining expected contributions to its Pension Plan during 2011 would be discretionary contributions, anticipated to be in the form of cash, and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

Security Ratings

Access to reasonably priced capital is dependent in part on credit and security ratings. 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 cost 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.

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 one time for a two-year period beginning January 1, 2011 and ending December 31, 2012. See Note 9 of Notes to Condensed Financial Statements for a discussion of the Company's short-term debt activity.

Issuance of New Long-Term Debt

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

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are 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 2010 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 2010 Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company's financial position, results of operations or cash flows. See Notes 11 and 12 of Notes to Condensed Financial Statements in this Form 10-Q and Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I of the Company's 2010 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 mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. 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 2010 Form 10-K. Except as set forth below and in Part II, Item 1. Legal Proceedings, there have been no material changes to such items.

Air

Hazardous Air Pollutants Emission Standards

On May 3, 2011, the EPA published proposed Maximum Achievable Control Technology regulations governing emissions of certain hazardous air pollutants from electric generating units. The proposal includes numerical standards for particulate matter, hydrogen chloride and mercury emissions from coal-fired boilers. In addition, the proposal includes work practice standards and an annual emission test to control dioxins and furans. Under the proposed rules, compliance is required within three years after finalization of the rule with a possibility of a one year extension. The EPA is currently accepting comments on the proposal and is under a consent decree deadline to issue a final rule by November 2011. The Company is evaluating what emission controls would be necessary to meet the proposed standards and the associated costs, which could be significant.

Regional Haze Control Measures

As described in the Company's 2010 Form 10-K, on February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP concluded that BART for reducing NOX emissions at all of the subject units should be the installation of low NOX burners (overfire air and flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits. The Company preliminarily estimates that the total cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be between $70 million and $130 million. With respect to SO2 emissions, the SIP included an agreement between the ODEQ and the Company that established BART for SO2 control at four coal-fired units located at the Company's Sooner and Muskogee generating stations as the continued use of low sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of Dry Scrubbers as BART for SO2 control from these units because the state determined that Dry Scrubbers were not cost effective on these units.

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On March 22, 2011, the EPA proposed to reject portions of the Oklahoma SIP and proposed a Federal implementation plan. While the EPA accepted Oklahoma's BART determination for NOX in the SIP, it rejected the SO2 BART determination for the Company. In its place, the EPA has proposed that the Company meet an SO2 emission rate of 0.06 pounds per million British thermal unit. The Company could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four coal-fired generating units at the Company's Muskogee and Sooner generating stations. The Company estimates that installing Dry Scrubbers on these units would cost the Company more than $1.0 billion. On May 23, 2011, the Company submitted comments on the proposed rule requesting that the Oklahoma SIP be approved and that the EPA not proceed with issuance of the Federal implementation plan.

Until the EPA takes final action on the Oklahoma 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 and Greenhouse Gas Emissions

In the absence of Federal legislation, the EPA is taking steps to regulate greenhouse gas emissions from stationary sources using its existing legal authority. On September 22, 2009, the EPA announced the adoption of the first comprehensive national system for reporting emissions of carbon dioxide and other greenhouse gases produced by major sources in the United States. The reporting requirements apply to large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain Company facilities. The rule requires the collection of data beginning on January 1, 2010 with the first annual reports due to the EPA on September 30, 2011. For petroleum and natural gas facilities, data collection begins on January 1, 2011, with the first annual report due on March 31, 2012. The Company already reports quarterly its carbon dioxide emissions from generating units subject to the Federal Acid Rain Program and is continuing to evaluate various options for reducing, avoiding, offsetting or sequestering its carbon dioxide emissions.

Notice of Violation

As previously reported, in July 2008, the Company received a request for information from the EPA regarding Federal Clean Air Act compliance at the Company's Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act's new source review process. The Company believes it has acted in full compliance with the Federal Clean Air Act and new source review process and is cooperating with the EPA. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects that occurred at the Company's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that the Company's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards (See Part II, Item 1 – Legal Proceedings – Opacity Notice for a related discussion). The Company has met with the EPA regarding the notice but cannot predict at this time what, if any, further actions may be necessary as a result of the notice. The EPA could seek to require the Company to install additional pollution control equipment and pay fines and penalties as a result of the allegations in the notice of violation. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation.

Cross-State Air Pollution Rule

On July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule to replace the former Clean Air Interstate Rule that was remanded by a Federal court as a result of legal challenges. On July 11, 2011, the EPA published a proposed rule in which the EPA proposes to make six additional states, including Oklahoma, subject to the Cross-State Air Pollution Rule for ozone-season NOX. If the proposed rule is finalized and Oklahoma becomes subject to the Cross-State Air Pollution Rule, the Company would be required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. The EPA is currently accepting comments on the proposed rule. The Company is evaluating what emission controls would be necessary to meet the proposed standards and the associated costs, which could be significant.

Supreme Court Decision

On June 20, 2011, the U.S. Supreme Court issued a decision that bars state and private parties from bringing Federal common law nuisance actions against electrical utility companies based on their alleged contribution to climate change. The Supreme Court's decision, which did not address state law claims, is expected to affect other pending Federal climate change litigation. Although the Company is not a defendant in any of these proceedings, additional litigation in Federal and state courts over climate change issues is continuing.

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Water Intakes

In March 2011, the EPA proposed rules pursuant to Section 316(b) of the Federal Clean Water Act to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. The EPA is currently taking comments on the proposed rules. When final rules are issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with the final water intake standards are not currently determinable, but could be significant.


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 and chief financial officer , 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 chief executive officer and chief financial officer, 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 chief executive officer and chief financial officer 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 2010 Form 10-K for a description of certain legal proceedings presently pending. Except as set forth below, there are no new significant cases to report against the Company and there have been no material changes in the previously reported proceedings.

1.Opacity Notice. On May 17, 2011, the Company entered into a Consent Order with the ODEQ related to alleged violations of Federal and state opacity standards from 2005 to present at the Company's Muskogee and Sooner generating stations. The Consent Order requires the Company to reach certain milestones with regard to the overall amount of time when opacity exceeds certain amounts. Beginning January 1, 2015, the Consent Order requires each unit at the Company's Muskogee and Sooner generating stations to have a rolling annual average of the time that opacity emissions are in excess of 20 percent to a level equal to or below one percent of the total time in a measurement period. The Company agreed to implement two specific projects and other measures as necessary to achieve the milestones established in the Consent Order. These projects and other measures are not expected to involve significant capital or ongoing operating expenses. The Company also agreed to pay a stipulated cash penalty of $150,000 and agreed to contribute another $150,000 to an ODEQ environmental fund for assisting small Oklahoma communities with their drinking water and wastewater treatment systems. The Company entered into the Consent Order without admitting or denying the allegations made by the ODEQ. In order to facilitate the court approval of the Consent Order, the ODEQ initiated the necessary legal action against the Company in state court on May 17, 2011. On June 2, 2011, the Consent Order was approved and entered by the District Court of Oklahoma County, Oklahoma. The Company considers this matter closed.

As previously reported, on March 18, 2011, the Gulf Coast Environmental Labor Coalition gave notice pursuant to the citizen suit provision of the Federal Clean Air Act that it intended to file a lawsuit against the Company seeking both injunctive relief to enjoin excess opacity emissions from the Company's Muskogee and Sooner generating stations and the assessment of civil penalties for alleged past violations of the applicable opacity limits. Because the Consent Order addresses the same alleged violations, the legal action by the ODEQ will prevent the Gulf Coast Environmental Labor Coalition from filing the lawsuit against the Company. Neither the ODEQ action against the Company in state court nor the Consent Order preclude the EPA from seeking additional relief in connection with the allegations of opacity emissions not in accordance with applicable new source performance

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standards that are contained in the previously disclosed notice of violation issued to the Company on April 26, 2011. The EPA has not indicated if it will seek any additional relief related to those allegations.


Item 1A.	Risk Factors.

There have been no significant changes in the Company's risk factors from those discussed in the Company's 2010 Form 10-K, which are incorporated herein by reference.


Item 6.	Exhibits.



Exhibit No.	Description
3.01	Copy of Restated Oklahoma Gas and Electric Company Certificate of Incorporation. (Filed as Exhibit 3.01 to the Company's Form 8-K filed May 19, 2011 (File No. 1-1097) and incorporated by reference herein).
3.02	Copy of Amended Oklahoma Gas and Electric Company By-laws dated May 19, 2011. (Filed as Exhibit 3.02 to the Company's Form 8-K filed May 19, 2011 (File No. 1-1097) and incorporated by reference herein).
4.01	Supplemental Indenture No. 12 dated as of May 15, 2011 between the Company and UMB Bank, N.A., as trustee, creating the Senior Notes. (Filed as Exhibit 4.01 to the Company's Form 8-K filed May 27, 2011 (File No. 1-1097) 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.
99.01	Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others related to the Company's rate case. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed May 19, 2011 (File No. 1-12579) and incorporated by reference herein)
99.02	Copy of APSC Order with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others related to the Company's rate case. (Filed as Exhibit 99.02 to OGE Energy's Form 8-K filed June 22, 2011 (File No. 1-12579) and incorporated by reference herein)
99.03	Copy of Settlement Agreement with Arkansas Public Service Commission Staff, the Arkansas Attorney General and others related to the Company's Smart Grid application. (Filed as Exhibit 99.01 to OGE Energy's Form 8-K filed June 28, 2011 (File No. 1-12579) and incorporated by reference herein)
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.

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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

August 4, 2011

OKLAHOMA GAS & ELECTRIC CO - FORM 10-Q - August 4, 2011

Attached files

OKLAHOMA GAS & ELECTRIC CO Reports