10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1481638
(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  R	Accelerated filer  £
Non-accelerated filer    £ (Do not check if a smaller reporting company)	Smaller reporting company  £

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 97,973,168 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

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 Consolidated Statements of Income	2
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4
Condensed Consolidated Balance Sheets	5
Condensed Consolidated Statements of Changes in Stockholders' Equity	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	50
Item 4. Controls and Procedures	50
Part II – OTHER INFORMATION
Item 1. Legal Proceedings	51
Item 1A. Risk Factors	51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 6. Exhibits	52
Signature	53

i

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
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
Atoka	Atoka Midstream LLC joint venture
BART	Best Available Retrofit Technology
Company	OGE Energy, collectively with its subsidiaries
Crossroads	OG&E's Crossroads wind project in Dewey County, Oklahoma
Dry Scrubbers	Dry flue gas desulfurization units with Spray Dryer Absorber
Enogex	OGE Holdings, collectively with its subsidiaries
Enogex LLC	Enogex LLC, collectively with its subsidiaries
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Energy
Enogex Holdings LLC Agreement	Amended and Restated Limited Liability Agreement of Enogex Holdings
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States
MEP	Midcontinent Express Pipeline, LLC
MMcf/d	Million cubic feet per day
NGLs	Natural gas liquids
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
OG&E	Oklahoma Gas and Electric Company
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings
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 OG&E's customers
Windspeed	OG&E's transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma

ii

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 its subsidiaries to access the capital markets and obtain financing on favorable terms;

• prices and availability of electricity, coal, natural gas and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, keep-whole and fixed-fee;

• business conditions in the energy and natural gas midstream industries;

• 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 OG&E 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;

• the higher degree of risk associated with the Company's nonregulated business compared with the Company's regulated utility business; 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.

1

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2011			2010			2011			2010
OPERATING REVENUES
Electric Utility operating revenues	$	568.7		$	512.8		$	990.8		$	956.8
Natural Gas Midstream Operations operating revenues	409.4			374.4			827.8			806.2
Total operating revenues	978.1			887.2			1,818.6			1,763.0
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	242.5			218.9			450.0			457.8
Natural Gas Midstream Operations cost of goods sold	307.6			287.6			633.3			618.8
Total cost of goods sold	550.1			506.5			1,083.3			1,076.6
Gross margin on revenues	428.0			380.7			735.3			686.4
OPERATING EXPENSES
Other operation and maintenance	146.6			135.0			284.9			258.6
Depreciation and amortization	74.7			71.2			148.7			141.5
Taxes other than income	24.5			23.0			51.6			48.0
Total operating expenses	245.8			229.2			485.2			448.1
OPERATING INCOME	182.2			151.5			250.1			238.3
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	7.0			3.4			13.3			6.5
Other expense	(3.5		)	(5.0		)	(5.8		)	(7.4		)
Net other income	9.4			0.7			17.9			3.7
INTEREST EXPENSE
Interest on long-term debt	35.8			33.4			71.2			67.0
Allowance for borrowed funds used during construction	(2.9		)	(1.0		)	(5.2		)	(2.2		)
Interest on short-term debt and other interest charges	1.6			1.6			2.6			3.3
Interest expense	34.5			34.0			68.6			68.1
INCOME BEFORE TAXES	157.1			118.2			199.4			173.9
INCOME TAX EXPENSE	47.8			40.3			60.4			70.8
NET INCOME	109.3			77.9			139.0			103.1
Less: Net income attributable to noncontrolling interests	6.3			0.6			11.2			1.6
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	103.0		$	77.3		$	127.8		$	101.5
BASIC AVERAGE COMMON SHARES OUTSTANDING	98.0			97.3			97.8			97.2
DILUTED AVERAGE COMMON SHARES OUTSTANDING	99.3			98.7			99.2			98.6
BASIC EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	1.05		$	0.79		$	1.31		$	1.04
DILUTED EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	1.04		$	0.78		$	1.29		$	1.03
DIVIDENDS DECLARED PER COMMON SHARE	$	0.3750		$	0.3625		$	0.7500		$	0.7250

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

2

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2011			2010		2011			2010
Net income	$	109.3		$	77.9	$	139.0		$	103.1
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.5 million,
$0.3 million, $0.9 million and $1.0 million, respectively	0.5			0.5		1.0			1.0
Amortization of prior service cost, net of tax of ($0.1) million,
$0, $0 and $0, respectively	—			0.1		0.2			0.1
Postretirement plans:
Amortization of deferred net loss, net of tax of $0.1 million,
$0.2 million, $0.6 million and $0.6 million, respectively	0.6			0.3		0.8			0.9
Amortization of deferred net transition obligation, net of tax of
($0.1) million, $0.1 million, $0 and $0.1 million, respectively	—			0.1		0.1			0.3
Amortization of prior service cost, net of tax of $0.3 million, $0,
$5.6 million and $0, respectively	(0.3		)	—		9.8			(0.2		)
Deferred commodity contracts hedging gains (losses), net of tax of $2.9
million, $7.8 million, $4.1 million and $6.2 million, respectively	5.5			12.3		7.0			9.6
Deferred interest rate swaps hedging gains, net of tax of $0, $0
$0.1 million and $0, respectively	0.1			—		0.2			0.1
Other comprehensive income (loss), net of tax	6.4			13.3		19.1			11.8
Comprehensive income (loss)	115.7			91.2		158.1			114.9
Less:  Comprehensive income attributable to noncontrolling interest
for sale of equity investment	—			—		(1.7		)	—
Less:  Comprehensive income attributable to noncontrolling interests	7.5			0.6		13.5			1.6
Total comprehensive income (loss) attributable to OGE Energy	$	108.2		$	90.6	$	146.3		$	113.3

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

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
(In millions)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	139.0		$	103.1
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	148.7			141.5
Deferred income taxes and investment tax credits, net	60.3			52.2
Allowance for equity funds used during construction	(10.2		)	(4.6		)
(Gain) loss on disposition and abandonment of assets	(3.3		)	0.9
Stock-based compensation expense	0.4			2.3
Price risk management assets	1.1			(4.4		)
Price risk management liabilities	6.8			11.4
Regulatory assets	6.8			6.8
Regulatory liabilities	3.3			(6.5		)
Other assets	5.4			6.2
Other liabilities	(38.3		)	(34.2		)
Change in certain current assets and liabilities
Accounts receivable, net	(47.0		)	(24.1		)
Accrued unbilled revenues	(39.8		)	(24.4		)
Income taxes receivable	—			150.6
Fuel, materials and supplies inventories	33.9			(28.5		)
Gas imbalance assets	(3.6		)	(1.8		)
Fuel clause under recoveries	(21.4		)	(0.6		)
Other current assets	3.5			8.9
Accounts payable	(6.1		)	4.8
Gas imbalance liabilities	1.0			(4.2		)
Fuel clause over recoveries	(20.6		)	(50.1		)
Other current liabilities	26.6			36.2
Net Cash Provided from Operating Activities	246.5			341.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(571.8		)	(306.2		)
Reimbursement of capital expenditures	21.6			12.9
Proceeds from sale of assets	17.5			1.7
Net Cash Used in Investing Activities	(532.7		)	(291.6		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	246.3			246.2
Contributions from noncontrolling interest partners	73.5			—
Increase (decrease) in short-term debt	66.1			(62.1		)
Issuance of common stock	7.5			9.8
Proceeds from line of credit	—			115.0
Retirement of long-term debt	—			(289.2		)
Distributions to noncontrolling interest partners	(6.1		)	—
Repayment of line of credit	(25.0		)	(50.0		)
Dividends paid on common stock	(73.3		)	(70.4		)
Net Cash Provided from (Used in) Financing Activities	289.0			(100.7		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2.8			(50.8		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2.3			58.1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5.1		$	7.3

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

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,		December 31,
	2011		2010
(In millions)	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5.1	$	2.3
Accounts receivable, less reserve of $1.7 and $1.9, respectively	324.9		277.9
Accrued unbilled revenues	96.6		56.8
Income taxes receivable	4.7		4.7
Fuel inventories	122.8		158.8
Materials and supplies, at average cost	85.4		83.3
Price risk management	0.9		1.4
Gas imbalances	6.1		2.5
Deferred income taxes	15.1		18.7
Fuel clause under recoveries	22.4		1.0
Other	21.2		24.7
Total current assets	705.2		632.1
OTHER PROPERTY AND INVESTMENTS, at cost	46.9		44.9
PROPERTY, PLANT AND EQUIPMENT
In service	9,414.5		9,188.0
Construction work in progress	774.8		460.0
Total property, plant and equipment	10,189.3		9,648.0
Less accumulated depreciation	3,255.1		3,183.6
Net property, plant and equipment	6,934.2		6,464.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	414.9		489.4
Price risk management	0.2		0.8
Other	34.1		37.5
Total deferred charges and other assets	449.2		527.7
TOTAL ASSETS	$	8,135.5	$	7,669.1

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

5

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

	June 30,			December 31,
	2011			2010
(In millions)	(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	211.1		$	145.0
Accounts payable	372.5			321.7
Dividends payable	36.7			36.6
Customer deposits	67.2			67.0
Accrued taxes	42.3			39.3
Accrued interest	54.3			53.1
Accrued compensation	48.9			43.3
Price risk management	12.2			16.8
Gas imbalances	7.7			6.7
Fuel clause over recoveries	9.3			29.9
Other	71.7			55.1
Total current liabilities	933.9			814.5
LONG-TERM DEBT	2,586.8			2,362.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	249.0			372.4
Deferred income taxes	1,512.8			1,434.8
Deferred investment tax credits	7.7			9.4
Regulatory liabilities	215.9			193.1
Price risk management	0.1			—
Deferred revenues	36.2			36.7
Other	44.7			45.3
Total deferred credits and other liabilities	2,066.4			2,091.7
Total liabilities	5,587.1			5,269.1
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders’ equity	994.7			969.2
Retained earnings	1,434.9			1,380.6
Accumulated other comprehensive loss, net of tax	(41.8		)	(60.2		)
Total OGE Energy stockholders' equity	2,387.8			2,289.6
Noncontrolling interests	160.6			110.4
Total stockholders' equity	2,548.4			2,400.0
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	8,135.5		$	7,669.1

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

6

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)

			Premium						Accumulated
			on						Other
	Common		Common			Retained			Comprehensive			Noncontrolling
(In millions)	Stock		Stock			Earnings			Income (Loss)			Interest			Total
Balance at December 31, 2010	$	1.0	$	968.2		$	1,380.6		$	(60.2	)	$	110.4		$	2,400.0
Comprehensive income (loss)
Net income	—		—			127.8			—			11.2			139.0
Other comprehensive
income (loss), net of tax	—		—			—			18.4			0.7			19.1
Comprehensive income (loss)	—		—			127.8			18.4			11.9			158.1
Dividends declared on
common stock	—		—			(73.5		)	—			—			(73.5		)
Issuance of common stock	—		7.5			—			—			—			7.5
Stock-based compensation	—		0.1			—			—			—			0.1
Contributions from
noncontrolling interest
partners	—		29.1			—			—			44.4			73.5
Distributions to noncontrolling
interest partners	—		—			—			—			(6.1		)	(6.1		)
Deferred income taxes
attributable to contributions
from noncontrolling interest
partners	—		(11.2		)	—			—			—			(11.2		)
Balance at June 30, 2011	$	1.0	$	993.7		$	1,434.9		$	(41.8	)	$	160.6		$	2,548.4
Balance at December 31, 2009	$	1.0	$	886.7		$	1,227.8		$	(74.7	)	$	20.0		$	2,060.8
Comprehensive income (loss)
Net income	—		—			101.5			—			1.6			103.1
Other comprehensive
income (loss), net of tax	—		—			—			11.8			—			11.8
Comprehensive income (loss)	—		—			101.5			11.8			1.6			114.9
Dividends declared on
common stock	—		—			(70.6		)	—			—			(70.6		)
Issuance of common stock	—		9.8			—			—			—			9.8
Stock-based compensation	—		4.8			—			—			—			4.8
Balance at June 30, 2010	$	1.0	$	901.3		$	1,258.7		$	(62.9	)	$	21.6		$	2,119.7

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

7

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

Organization

The Company 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 conducts these activities through four business segments:  (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  All significant intercompany transactions have been eliminated in consolidation.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC.  OG&E was incorporated in 1902 under the laws of the Oklahoma Territory.  OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enogex is a provider of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting, storing and marketing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.  Enogex's operations are organized into three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. Through OGE Holdings, the Company indirectly owns an 86.7 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company (see Note 3).  The Company continues to consolidate 100 percent of Enogex Holdings in its consolidated financial statements as OGE Energy has a controlling financial interest over the operations of Enogex Holdings.  Prior to November 1, 2010, OER, whose primary operations are in natural gas marketing, was directly owned by OGE Energy.  On November 1, 2010, OGE Energy distributed the equity interests in OER to Enogex LLC.  Accordingly, the discussion that follows includes the results of OER in Enogex's results for all periods presented. Also, Enogex LLC holds a 50 percent ownership interest in Atoka.  The Company has consolidated 100 percent of Atoka in its consolidated financial statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka.

Basis of Presentation

The Condensed Consolidated 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 consolidated 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 Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2010 Form 10-K.

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, OG&E, 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

8

results from specific decisions by regulators granting such ratemaking treatment.

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

The following table is a summary of OG&E'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 Consolidated Balance Sheets.

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

As discussed in Note 15 in OG&E'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 OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. As a result, OG&E 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.

Reclassifications

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

9

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 Consolidated Statements of Comprehensive Income after its Condensed Consolidated Statements of Income.

3. ArcLight Transaction

The following table summarizes changes in OGE Energy's equity attributable to changes in its ownership interest in Enogex Holdings during the six months ended June 30, 2011. There were no contributions by OGE Energy or the ArcLight group to fund Enogex LLC's 2011 capital requirements during the three months ended June 30, 2011. Also, there were no sales of additional membership interests in Enogex Holdings to the ArcLight group during the three months ended June 30, 2011.

(In millions)
Net income attributable to OGE Energy	$	127.8
Transfers (to) from the noncontrolling interest
Increase in paid-in capital for sale of 100,000 units of Enogex Holdings	0.9
Increase in paid-in capital for issuance of 4,303,007 units of Enogex Holdings	28.2
Decrease in paid-in capital for deferred income taxes attributable to the sale and issuance of units
of Enogex Holdings	(11.2		)
Net transfers from the noncontrolling interest	17.9
Change from net income attributable to OGE Energy and transfers from noncontrolling interest	$	145.7

The following table summarizes changes in OGE Holdings' and the ArcLight group's membership interest in Enogex Holdings for the six months ended June 30, 2011. Prior to November 1, 2010, Enogex Holdings was wholly owned by OGE Energy.

(In millions)	OGE Holdings		ArcLight group		Total
Balance at December 31, 2010 (units)	90.1		9.9		100.0
Ownership percentage at December 31, 2010	90.1	%	9.9	%	100.0	%
Sale of 100,000 units of Enogex Holdings (A)	(0.1	)	0.1		—
Issuance of 4,303,007 units of Enogex Holdings (B)	0.4		3.9		4.3
Balance at June 30, 2011 (units)	90.4		13.9		104.3
Ownership percentage at June 30, 2011	86.7	%	13.3	%	100.0	%

(A) On February 1, 2011, OGE Energy sold a 0.1 percent membership interest in Enogex Holdings to the ArcLight group for $1.9 million.

(B) In February 2011, OGE Energy and the ArcLight group made contributions of $8.0 million and $71.6 million, respectively, to fund a portion of Enogex LLC's 2011 capital requirements.

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Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings makes quarterly distributions to its partners. The below table summarizes these distributions during the six months ended June 30, 2011.

	OGE Holdings		ArcLight group's
(In millions)	Portion		Portion		Total Distribution
First quarter 2011	$	7.5	$	0.8	$	8.3
Second quarter 2011	34.3		5.3		39.6
Total	$	41.8	$	6.1	$	47.9

4. 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 and examples of each 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. Instruments classified as Level 1 include natural gas futures, swaps and option transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

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 over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing.

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).  Instruments classified as Level 3 include NGLs options.

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.  The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining.  Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.  Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, NGLs options contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management's best estimate of fair value.  These contracts are classified as Level 3.

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.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset.  The reporting entity's choice to offset or not must be applied consistently.  A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other

11

conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets.  The Company has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at June 30, 2011 and December 31, 2010 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010.

June 30, 2011
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	12.3		$	12.7		$	—	$	—
Significant other observable inputs (Level 2)	1.7			15.4			6.1		5.2
Significant unobservable inputs (Level 3)	2.5			—			—		—
Total fair value	16.5			28.1			6.1		5.2
Netting adjustments	(15.4		)	(15.8		)	—		—
Total	$	1.1		$	12.3		$	6.1	$	5.2
December 31, 2010
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	20.6		$	20.2		$	—	$	—
Significant other observable inputs (Level 2)	2.7			30.7			2.5		2.8
Significant unobservable inputs (Level 3)	13.3			—			—		—
Total fair value	36.6			50.9			2.5		2.8
Netting adjustments	(34.4		)	(34.1		)	—		—
Total	$	2.2		$	16.8		$	2.5	$	2.8

(A) The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $2.5 million and $3.9 million at June 30, 2011 and December 31, 2010, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

	Commodity Contracts
	Assets						Liabilities
(In millions)	2011			2010			2011		2010
Balance at January 1	$	13.3		$	49.0		$	—	$	14.7
Total gains or losses
Included in other comprehensive income	(4.8		)	(3.9		)	—		(5.1		)
Settlements	(3.3		)	(4.1		)	—		(1.4		)
Balance at March 31	$	5.2		$	41.0		$	—	$	8.2
Total gains or losses
Included in other comprehensive income	(1.0		)	7.2			—		(3.7		)
Settlements	(1.7		)	(6.1		)	—		(2.7		)
Balance at June 30	$	2.5		$	42.1		$	—	$	1.8

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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 Assets
Energy Derivative Contracts	$	1.1	$	1.1	$	2.2	$	2.2
Price Risk Management Liabilities
Energy Derivative Contracts	$	12.3	$	12.3	$	16.8	$	16.8
Long-Term Debt
OG&E Senior Notes	$	1,903.7	$	2,115.4	$	1,655.0	$	1,831.5
OGE Energy Senior Notes	99.7		109.0		99.7		106.4
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Enogex LLC Senior Notes	448.0		494.2		447.8		480.7
Enogex LLC Revolving Credit Agreement	—		—		25.0		25.0

The carrying value of the financial instruments on the Condensed Consolidated 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.  However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values.  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.

5. 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 primarily uses forward physical contracts, commodity price swap contracts and commodity price option features to manage the Company's commodity price risk exposures. Commodity derivative instruments used by the Company are as follows:

• NGLs put options and NGLs swaps are used to manage Enogex's NGLs exposure associated with its processing agreements;

• natural gas swaps are used to manage Enogex's keep-whole natural gas exposure associated with its processing operations and Enogex's natural gas exposure associated with operating its gathering, transportation and storage assets;

• natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OER's natural gas exposure associated with its storage and transportation contracts; and

• natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OER's marketing and trading activities.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated 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) commodity contracts for the purchase and sale of natural gas used in or produced by its operations, (ii) commodity contracts for the sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.  Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

13

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. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument.  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.

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing, pipeline and storage operations (operational gas hedges).  The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex's cash flow hedges at June 30, 2011 mature during the remainder of 2011.

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

Derivative instruments not designated as hedging instruments are utilized in OER's asset management, marketing and trading activities.  For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

14

Quantitative Disclosures Related to Derivative Instruments

At June 30, 2011, the Company had the following derivative instruments that were designated as cash flow hedges.

	2011 Gross Notional
(In millions)	Volume (A)
Enogex processing hedges
NGLs sales	0.7
Natural gas purchases	2.6
Enogex marketing hedges
Natural gas sales	1.6

(A) Natural gas in Million British thermal unit; NGLs in barrels.

At June 30, 2011, the Company had the following derivative instruments that were not designated as hedging instruments.

(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	15.4	48.5
Fixed Swaps/Futures	55.5	54.3
Options	9.1	10.5
Basis Swaps	9.1	8.4

(A) Natural gas in Million British thermal unit.  

(B) 90.0 percent of the natural gas contracts have durations of one year or less, 6.8 percent have durations of more than one year and less than two years and 3.2 percent have durations of more than two years.

(C) Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

(D) Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at June 30, 2011 are as follows:

		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	2.5	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		14.4
Financial Futures/Swaps	Other Current Assets	0.5		—
Total		$	3.0	$	14.4
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.2	$	0.1
	Other Current Assets	12.0		13.1
Physical Purchases/Sales	Current PRM	0.8		0.3
	Non-Current PRM	0.2		0.1
Financial Options	Other Current Assets	0.3		0.1
Total		$	13.5	$	13.7
Total Gross Derivatives (A)		$	16.5	$	28.1

(A) See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at June 30, 2011.

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The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2010 are as follows:

		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	13.3	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		28.8
	Other Current Assets	0.6		0.3
Total		$	13.9	$	29.1
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	—	$	0.1
	Other Current Assets	20.0		19.8
Physical Purchases/Sales	Current PRM	1.4		1.2
	Non-Current PRM	0.8		—
Financial Options	Other Current Assets	0.5		0.7
Total		$	22.7	$	21.8
Total Gross Derivatives (A)		$	36.6	$	50.9

(A) See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2010.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(2.4	)	$	(3.3	)	$	—
Natural Gas Financial Futures/Swaps	0.1			(7.4		)	—
Total	$	(2.3	)	$	(10.7	)	$	—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(2.9	)
Natural Gas Financial Futures/Swaps	(0.2		)
Total	$	(3.1	)

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The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2010.

Derivatives in Cash Flow Hedging Relationships

			Amount Reclassified
	Amount Recognized		from Accumulated Other			Amount
	in Other		Comprehensive Income			Recognized in
(In millions)	Comprehensive Income		into Income			Income
NGLs Financial Options	$	10.5	$	1.1		$	—
NGLs Financial Futures/Swaps	2.0		(0.5		)	—
Natural Gas Financial Futures/Swaps	—		(8.6		)	—
Total	$	12.5	$	(8.0	)	$	—

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(3.7	)
Natural Gas Financial Futures/Swaps	(0.6		)
Total	$	(4.3	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(9.2	)	$	(5.8	)	$	—
Natural Gas Financial Futures/Swaps	(0.1		)	(14.7		)	—
Total	$	(9.3	)	$	(20.5	)	$	—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(5.0	)
Natural Gas Financial Futures/Swaps	(0.4		)
Total	$	(5.4	)

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The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2010.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income			into Income			Income
NGLs Financial Options	$	11.0		$	0.5		$	—
NGLs Financial Futures/Swaps	3.3			(1.8		)	—
Natural Gas Financial Futures/Swaps	(9.9		)	(12.0		)	0.1
Total	$	4.4		$	(13.3	)	$	0.1

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(3.8	)
Natural Gas Financial Futures/Swaps	0.2
Total	$	(3.6	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income into income (effective portion) and amounts recognized in income (ineffective portion) for the three and six months ended June 30, 2011 and 2010, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the three and six months ended June 30, 2011 and 2010, if any, are reported in Operating Revenues. 

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, at June 30, 2011, the Company would have been required to post $13.8 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at June 30, 2011.  In addition, the Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

6. 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 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	$	1.9	$	1.5	$	3.7	$	3.1
Earnings per share	0.8		0.4		3.0		0.8
Total performance units	2.7		1.9		6.7		3.9
Restricted stock	0.2		0.3		0.5		0.4
Total compensation expense	$	2.9	$	2.2	$	7.2	$	4.3
Income tax benefit	$	1.1	$	0.9	$	2.8	$	1.6

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

	Shares	Fair Value
Grants
Restricted stock	829	$50.61

The Company 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 the Company's stock incentive plans related to exercised stock options, restricted stock grants and payouts of earned performance units. 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. The Company received $0.1 million and $0.8 million, respectively, during the three and six months ended June 30, 2011 related to exercised stock options and realized an income tax benefit for the tax deductions from the exercised stock options of less than $0.1 million and $0.2 million, respectively, during the three and six months ended June 30, 2011.

7. Accumulated Other Comprehensive Income (Loss)

The following table summarizes the components of accumulated other comprehensive loss at June 30, 2011 and December 31, 2010 attributable to OGE Energy.  At both June 30, 2011 and December 31, 2010, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka.

	June 30,			December 31,
(In millions)	2011			2010
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	(30.1	)	$	(31.1	)
Prior service cost	(0.3		)	(0.5		)
Postretirement plans:
Net loss	(12.8		)	(13.6		)
Prior service cost	9.8			—
Net transition obligation	(0.2		)	(0.3		)
Deferred commodity contracts hedging losses	(12.5		)	(19.5		)
Deferred interest rate swaps hedging losses	(0.8		)	(1.0		)
Total accumulated other comprehensive loss	(46.9		)	(66.0		)
Less:  Accumulated other comprehensive loss attributable to noncontrolling interests	(5.1		)	(5.8		)
Accumulated other comprehensive loss, net of tax	$	(41.8	)	$	(60.2	)

8. Income Taxes

The Company 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.  OG&E earns both Federal and Oklahoma state tax credits associated with the production from its wind farms.  In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

9. Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 64,849 shares and 145,846 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months ended June 30, 2011 and received proceeds of $3.4 million and $7.2 million, respectively, during the three and six months ended June 30, 2011.  The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital requirements or working capital needs.  At June 30, 2011, there were 2,500,442 shares of unissued common stock reserved for issuance under the Company's

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Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings Per Share

Basic earnings per share is calculated by dividing net income attributable to OGE Energy by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units. Basic and diluted earnings per share for the Company were calculated as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2011		2010		2011		2010
Net Income Attributable to OGE Energy	$	103.0	$	77.3	$	127.8	$	101.5
Average Common Shares Outstanding
Basic average common shares outstanding	98.0		97.3		97.8		97.2
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.3		1.4		1.4		1.4
Diluted average common shares outstanding	99.3		98.7		99.2		98.6
Basic Earnings Per Average Common Share
Attributable to OGE Energy Common Shareholders	$	1.05	$	0.79	$	1.31	$	1.04
Diluted Earnings Per Average Common Share
Attributable to OGE Energy Common Shareholders	$	1.04	$	0.78	$	1.29	$	1.03
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

10.           Long-Term Debt

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

OG&E 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, OG&E is obligated to repurchase such unremarketed bonds.  As OG&E 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 Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

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

OG&E Issuance of New Long-Term Debt

On May 24, 2011, OG&E 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. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.

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11. Short-Term Debt and Credit Facilities

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.  The short-term debt balance was $211.1 million and $145.0 million at June 30, 2011 and December 31, 2010, respectively.  The following table provides information regarding the Company's revolving credit agreements and available cash at June 30, 2011.

Revolving Credit Agreements and Available Cash
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	596.0	$	211.1	0.34	%	(D)	December 6, 2012
OG&E (C)	389.0		2.2		0.14	%	(D)	December 6, 2012
Enogex LLC (E)	250.0		—		—	%	(D)	March 31, 2013
	1,235.0		213.3		0.34	%
Cash	5.1		N/A		N/A			N/A
Total	$	1,240.1	$	213.3	0.34	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2011.

(B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  At June 30, 2011, there was $211.1 million in outstanding commercial paper borrowings.

(C) This bank facility is available to back up OG&E'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.

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

(E) This bank facility is available to provide revolving credit borrowings for Enogex LLC.  As Enogex LLC's credit agreement matures on March 31, 2013, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Condensed Consolidated Balance Sheets.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions.  Pricing grids associated with the 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 the Company's short-term borrowings, but a reduction in 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.

OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis.  OG&E 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.

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12. Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated 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	$	4.4		$	4.0		$	8.8		$	8.4
Interest cost	8.3			8.1			16.6			15.9
Expected return on plan assets	(11.3		)	(10.5		)	(22.7		)	(21.2		)
Amortization of net loss	4.8			5.5			9.6			10.6
Amortization of unrecognized prior service cost	0.6			0.6			1.2			1.2
Net periodic benefit cost	$	6.8		$	7.7		$	13.5		$	14.9

	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)
Service cost	$	0.2	$	0.2	$	0.5	$	0.4
Interest cost	0.2		0.1		0.3		0.2
Amortization of net loss	0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost	0.2		0.3		0.4		0.4
Net periodic benefit cost	$	0.7	$	0.7	$	1.4	$	1.2

(A) In addition to the $7.5 million and $8.4 million of net periodic benefit cost recognized during the three months ended June 30, 2011 and 2010, respectively, OG&E 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 $14.9 million and $16.1 million of net periodic benefit cost recognized during the six months ended June 30, 2011 and 2010, respectively, OG&E 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).

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011 (C)			2010			2011 (C)			2010
Service cost	$	0.9		$	0.9		$	1.8		$	2.1
Interest cost	3.1			4.3			6.2			8.5
Expected return on plan assets	(1.3		)	(1.8		)	(2.6		)	(3.5		)
Amortization of transition obligation	0.7			0.7			1.4			1.4
Amortization of net loss	4.5			3.4			9.1			6.1
Amortization of unrecognized prior service cost	(4.1		)	—			(8.2		)	—
Net periodic benefit cost	$	3.8		$	7.5		$	7.7		$	14.6

(C) In addition to the $3.8 million and $7.7 million of net periodic benefit cost recognized during the three and six months ended June 30, 2011, respectively, OG&E 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).

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Pension Plan Funding

The Company previously disclosed in its 2010 Form 10-K that it may contribute up to $50 million to its Pension Plan during 2011.  During the six months ended June 30, 2011, the Company contributed $40 million to its Pension Plan and 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.

13.         Report of Business Segments

The Company's business is divided into four segments for financial reporting purposes.  These segments are as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  Other Operations primarily includes the operations of the holding company.  Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.  In reviewing its segment operating results, the Company focuses on operating income as its measure of segment profit and loss, and, therefore, has presented this information below.  The following tables summarize the results of the Company's business segments for the three and six months ended June 30, 2011 and 2010.

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
June 30, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	568.7	$	108.0	$	289.1	$	168.3		$	—		$	(156.0	)	$	978.1
Cost of goods sold	254.3		69.5		210.9		170.4			—			(155.0		)	550.1
Gross margin on revenues	314.4		38.5		78.2		(2.1		)	—			(1.0		)	428.0
Other operation and maintenance	110.2		13.0		26.3		2.0			(4.2		)	(0.7		)	146.6
Depreciation and amortization	52.1		5.8		13.4		0.1			3.3			—			74.7
Taxes other than income	18.8		3.3		1.7		(0.1		)	0.8			—			24.5
Operating income (loss)	$	133.3	$	16.4	$	36.8	$	(4.1	)	$	0.1		$	(0.3	)	$	182.2
Total assets	$	6,290.5	$	2,297.3	$	1,106.7	$	80.2		$	2,937.3		$	(4,576.5	)	$	8,135.5

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
June 30, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	512.8	$	97.1	$	235.4	$	189.0		$	—		$	(147.1	)	$	887.2
Cost of goods sold	230.8		60.9		168.6		192.9			—			(146.7		)	506.5
Gross margin on revenues	282.0		36.2		66.8		(3.9		)	—			(0.4		)	380.7
Other operation and maintenance	101.2		12.6		23.5		2.1			(3.5		)	(0.9		)	135.0
Depreciation and amortization	50.6		5.4		12.5		—			2.7			—			71.2
Taxes other than income	17.2		3.4		1.6		—			0.8			—			23.0
Operating income (loss)	$	113.0	$	14.8	$	29.2	$	(6.0	)	$	—		$	0.5		$	151.5
Total assets	$	5,775.9	$	1,585.2	$	907.9	$	104.5		$	2,691.6		$	(3,771.0	)	$	7,294.1

			Transportation		Gathering
Six Months Ended	Electric		and		and					Other
June 30, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	990.8	$	208.2	$	555.8	$	366.4		$	—		$	(302.6	)	$	1,818.6
Cost of goods sold	473.7		133.5		407.2		369.7			—			(300.8		)	1,083.3
Gross margin on revenues	517.1		74.7		148.6		(3.3		)	—			(1.8		)	735.3
Other operation and maintenance	216.0		22.1		53.1		4.1			(8.9		)	(1.5		)	284.9
Depreciation and amortization	103.9		11.2		26.9		0.1			6.6			—			148.7
Taxes other than income	37.9		7.6		3.6		0.1			2.4			—			51.6
Operating income (loss)	$	159.3	$	33.8	$	65.0	$	(7.6	)	$	(0.1	)	$	(0.3	)	$	250.1
Total assets	$	6,290.5	$	2,297.3	$	1,106.7	$	80.2		$	2,937.3		$	(4,576.5	)	$	8,135.5

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			Transportation		Gathering
Six Months Ended	Electric		and		and					Other
June 30, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	956.8	$	208.2	$	483.3	$	434.7		$	—		$	(320.0	)	$	1,763.0
Cost of goods sold	481.6		127.1		348.6		437.2			—			(317.9		)	1,076.6
Gross margin on revenues	475.2		81.1		134.7		(2.5		)	—			(2.1		)	686.4
Other operation and maintenance	195.1		23.6		44.8		4.8			(7.6		)	(2.1		)	258.6
Depreciation and amortization	100.3		10.8		24.9		—			5.5			—			141.5
Taxes other than income	34.9		7.3		3.5		0.2			2.1			—			48.0
Operating income (loss)	$	144.9	$	39.4	$	61.5	$	(7.5	)	$	—		$	—		$	238.3
Total assets	$	5,775.9	$	1,585.2	$	907.9	$	104.5		$	2,691.6		$	(3,771.0	)	$	7,294.1

14. Commitments and Contingencies

Except as set forth below and in Note 15, the circumstances set forth in Notes 14 and 15 to the Company's Consolidated 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.

OG&E Railcar Lease Agreement

OG&E has a noncancellable operating lease with purchase options, covering 1,446 coal hopper railcars to transport coal from Wyoming to OG&E's coal-fired generation units.  Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011.  At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease.  If OG&E 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, OG&E would be responsible for the difference in those values up to a maximum of $23.7 million.

On February 10, 2009, OG&E 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.

OG&E 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.

OG&E Wind Power Purchase Commitment

As previously disclosed, OG&E 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 OG&E will purchase its electric output.

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 Consolidated Financial Statements.  Except as otherwise stated above, in Note 15 below, in Item 1 of Part II of this Form 10-Q, in Notes 14 and 15 of Notes to Consolidated 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 consolidated financial position, results of operations or cash flows.

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15. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 15 to the Company's Consolidated 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

OG&E Wholesale Agreement

On May 28, 2009, OG&E sent a termination notice to the Arkansas Valley Electric Cooperative that OG&E would terminate its wholesale power agreement to all points of delivery where OG&E sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011.  In December 2010, OG&E and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby OG&E will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015.  On January 3, 2011, OG&E 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 OG&E'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.

OG&E Long-Term Gas Supply Agreements    

In May 2010, the OCC approved OG&E's request for a waiver of the competitive bid rules to allow OG&E to negotiate desired long-term gas purchase agreements. On June 29, 2010, OG&E 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 OG&E and account for 25 percent of its currently projected natural gas fuel supply needs over the same time period. On September 26, 2010, OG&E filed a motion with the OCC to dismiss this case. On July 5, 2011, OG&E received an order from the OCC dismissing the case without prejudice.

OG&E Crossroads Wind Project

As previously disclosed, on July 29, 2010, OG&E received an order from the OCC authorizing OG&E 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, OG&E entered into an interconnection agreement with the SPP for Crossroads which will allow Crossroads to interconnect at the anticipated 227.5 megawatts. 

OG&E 2010 Arkansas Rate Case Filing

On September 28, 2010, OG&E 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. OG&E 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-OG&E transmission owners throughout the SPP that have been allocated to OG&E 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 OG&E 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 OG&E 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 OG&E'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.

OG&E SPP Cost Tracker

On October 7, 2010, OG&E 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-OG&E transmission owners throughout the SPP that have been allocated to OG&E through

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the FERC-approved transmission ratesand (ii) SPP administrative fees. OG&E 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.  OG&E also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give OG&E 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 OG&E to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. OG&E 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 OG&E 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 OG&E's 2011 Oklahoma general rate case filing, OG&E 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 OG&E by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.

OG&E FERC Transmission Rate Incentive Filing

On February 18, 2011, OG&E 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.  OG&E requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five345 kilovolt Extra High Voltage transmission projects to be constructed and owned by OG&E within the SPP's region.  OG&E 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 OG&E'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 15 of the Company's 2010 Form 10-K.

OG&E 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 OG&E customers, on March 15, 2011, OG&E filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting.  In seeking approval of these programs, OG&E 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 OG&E's energy efficiency plan for 2011 and approving OG&E's energy efficiency cost recovery rider for 2011. In Arkansas, OG&E'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 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 OG&E) 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 OG&E) 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

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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 OG&E 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 OG&E. Nevertheless, at the present time, the Company has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.

OG&E Smart Grid Project

As previously reported in the Company's 2010 Form 10-K, on December 17, 2010, OG&E 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, OG&E reached a settlement agreement with all the parties to the APSC consideration of OG&E'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. OG&E 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 OG&E 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) OG&E 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 OG&E'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 OG&E's next general rate case. OG&E 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 OG&E'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 OG&E's application of the 2009 fuel adjustment clause.  On December 28, 2010, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. An intervenor representing a group of OG&E's industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by OG&E to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing natural gas supply agreement between OG&E and Enogex.  OG&E 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.

OG&E Pension Tracker Modification Filing

On February 22, 2011, OG&E filed an application with the OCC requesting that OG&E's pension tracker be modified to include the difference between the level of retiree medical costs authorized in OG&E'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 OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. A hearing in this matter was held on July 14, 2011. OG&E expects to receive a decision from the OCC during the third quarter of 2011.

OG&E 2011 Oklahoma Rate Case Filing

As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E 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, OG&E 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

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two and one-half years. The case is expected to proceed through the second half of 2011. OG&E expects to receive an order from the OCC in early 2012.

Enogex FERC Section 311 2007 Rate Case

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for Section 311 service in the East Zone and West Zone. Enogex's filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008.  A number of parties intervened and some also filed protests. Enogex did not place the increased rates set forth in its October 2007 rate filing into effect but rather continued to provide interruptible Section 311 service under the maximum Section 311 rates for both zones approved by the FERC in the previous rate case. A final settlement was filed with the FERC on August 5, 2010 and an order is pending. With the filing of Enogex's 2009 rate case discussed below, the rate period for the 2007 rate case became a limited locked-in period from January 2008 through May 2009.

On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex 2007 rate case with a separate Enogex application pending before the FERC allowing Enogex to lease firm capacity to MEP and with separate applications filed by MEP with the FERC for a certificate to construct and operate the MEP pipeline and to lease firm capacity from Enogex. Enogex and MEP separately opposed this intervenor's protests and assertions in its initial and subsequent pleadings. On July 25, 2008, the FERC issued an order (i) approving the MEP project including the approval of a limited jurisdiction certificate and (ii) authorizing the Enogex lease agreement with MEP. Accordingly, Enogex proceeded with the construction of facilities necessary to implement this service. On August 25, 2008, a protestor sought rehearing which the FERC denied. Enogex commenced service to MEP under the lease agreement on June 1, 2009. On July 16, 2009, the protestor filed, with the United States Court of Appeals for the District of Columbia Circuit, a petition for review of the FERC's orders approving the MEP construction and the MEP lease of capacity from Enogex requesting that such orders be modified or set aside on the grounds that they are arbitrary, capricious and contrary to law.  On December 28, 2010, the Court of Appeals issued an opinion generally upholding the FERC's orders, but remanding the case for further explanation of one aspect of the FERC's reasoning.  The Court of Appeals emphasized that it was not vacating the FERC's orders and that its approval of the Enogex lease agreement with MEP remains in effect and legally binding.  On remand, the FERC must clarify that its decision was based on a finding that the lease does not adversely affect existing customers on Enogex's system.  Enogex anticipates that the FERC will issue an order on remand in the first half of 2011.  On January 21, 2011, Apache Corporation filed a motion asking the FERC to establish procedures on remand and to either condition the lease on Enogex's willingness to provide firm Section 311 transportation service to existing customers on all portions of its system or to establish an expedited briefing schedule.  On February 7, 2011, Enogex, MEP and Chesapeake Energy Corporation filed a joint answer asking the FERC to find, among other things, that the reduction in the amount of interruptible transportation capacity available due to the MEP lease did not have an adverse affect on Apache Corporation and to acknowledge that Apache Corporation's request to condition the lease on the provision of West Zone 311 firm transportation service has been addressed as Enogex filed a rate case on January 28, 2011 proposing to implement such service effective March 1, 2011. On March 1, 2011, Apache Corporation filed an answer seeking to refute some of the arguments presented in the joint answer filed by Enogex, MEP and Chesapeake Energy Corporation.  On March 3, 2011, the FERC issued an order on remand affirming the authorizations previously granted to Enogex and MEP and clarifying the legal standard applied in response to the court's directive.  On April 4, 2011, Apache Corporation filed a request for rehearing of the FERC's order on remand. The FERC issued a tolling order on May 4, 2011 indefinitely extending the time for the FERC to act on Apache Corporation's motion for rehearing. Once the FERC acts on Apache Corporation's request for rehearing, the order on remand and the order on rehearing become subject to appeal before the United States Court of Appeals for the District of Columbia Circuit.

Enogex FERC Section 311 2009 Rate Case

On March 27, 2009, Enogex filed a petition for rate approval with the FERC to set the maximum rates for its new firm East Zone Section 311 transportation service and to revise the rates for its existing East and West Zone interruptible Section 311 transportation service. In anticipation of offering this new service, Enogex had filed with the FERC, as required by the FERC's regulations, a revised Statement of Operating Conditions Applicable to Transportation Services to describe the terms, conditions and operating arrangements for the new service.  Enogex made the Statement of Operating Conditions filing on February 27, 2009.  Enogex began offering firm East Zone Section 311 transportation service on April 1, 2009. The revised East and West Zone zonal rates for the Section 311 interruptible transportation service became effective June 1, 2009. The rates for the firm East Zone Section 311 transportation service and the increase in the rates for East and West Zone and interruptible Section 311 service are being collected, subject to refund, pending the FERC approval of the proposed rates. A number of parties intervened in both the rate case and the Statement of Operating Conditions filing and some additionally filed protests. On January 4, 2010, the FERC Staff submitted an offer proposing various adjustments to Enogex's filed cost of service. On April 27, 2010, Enogex submitted comments to the FERC Staff stating that it would agree to the offer, contingent upon all parties agreeing to support or not oppose.  Parties have until September 15, 2011 to submit comments stating whether they support, or do not oppose, the FERC Staff's offer. 

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Enogex FERC Section 311 2011 RateCase

On January 28, 2011, Enogex submitted a new rate filing to the FERC to set the maximum rate for a new firm Section 311 transportation service in the West Zone of its system and to revise the currently effective maximum rates for Section 311 interruptible transportation service in the East Zone and West Zone.  Along with establishing the rate for a new firm service in the West Zone, Enogex's filing requested a decrease in the maximum interruptible zonal rates in the West Zone and to retain the currently effective rates for firm and interruptible services in the East Zone.  Enogex reserved the right to implement the higher rates for firm and interruptible services in the East Zone supported by the cost of service to the extent an expeditious settlement agreement cannot be reached in the proceeding.  Enogex proposed that the rates be placed into effect on March 1, 2011.  At Enogex's request, the protest deadline was extended to September 15, 2011.  The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action.

Enogex 2011 Fuel Filing

On February 28, 2011, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2011 through March 31, 2012).  Along with the revised fuel percentages, Enogex also requested authority to revise its Statement of Operating Conditions to permanently change the annual filing date to February 28.  The deadline for interventions and protests on Enogex's filing was March 15, 2011, and no protests were filed.  A FERC order is pending.

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

Introduction

The Company 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 conducts these activities through four business segments:  (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC.  OG&E was incorporated in 1902 under the laws of the Oklahoma Territory.  OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enogex is a provider of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting, storing and marketing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.  Enogex's operations are organized into three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing.  Through OGE Holdings, the Company indirectly owns an 86.7 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC.  Prior to November 1, 2010, OER, whose primary operations are in natural gas marketing, was directly owned by OGE Energy.  On November 1, 2010, OGE Energy distributed the equity interests in OER to Enogex LLC.  Accordingly, the discussion that follows includes the results of OER in Enogex's results for all periods presented.  Also, Enogex LLC holds a 50 percent ownership interest in Atoka. 

Overview

Financial Strategy

The Company'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. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated natural gas midstream business.  The Company intends to maintain the majority of its assets in the regulated utility business, however, the Company anticipates significant growth opportunities for its natural gas midstream business.  With respect to its natural gas midstream business, the Company intends to focus on growing products and services with limited or manageable commodity price exposure and intends to seek to mitigate exposure to fluctuations in commodity prices by continuing to increase the percentage that fee-based processing agreements represent of the total processing volumes.  The Company's financial objectives include a long-term annual earnings growth rate of five to seven percent on a weather-normalized basis, maintaining a strong credit rating as well as

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increasing the dividend to meet the Company's dividend payout objectives.  The target payout ratio for the Company is to pay out as dividends no more than 60 percent of its normalized earnings on an annual basis.  The target payout ratio has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets, the composition of the Company's assets and investment opportunities.  The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

Summary of Operating Results

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

Net income attributable to OGE Energy was $103.0 million, or $1.04 per diluted share, during the three months ended June 30, 2011, as compared to $77.3 million, or $0.78 per diluted share, during the same period in 2010.  The increase in net income attributable to OGE Energy of $25.7 million, or 33.2 percent, during the three months ended June 30, 2011 as compared to the same period in 2010 was primarily due to:

• an increase in net income at OG&E of $18.6 million, or 31.0 percent, or $0.18 per diluted share of the Company's common stock, primarily due to a higher gross margin primarily from warmer weather in OG&E'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; and

• an increase in net income at Enogex of $6.4 million, or 34.4 percent, or $0.06 per diluted share of the Company's common stock, primarily due to a higher gross margin primarily from higher NGLs prices and higher average natural gas prices, higher other income primarily due to the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets and lower interest expense partially offset by higher operation and maintenance expense, higher income tax expense and the equity sale of a membership interest in Enogex Holdings to the ArcLight group.

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

Net income attributable to OGE Energy was $127.8 million, or $1.29 per diluted share, during the six months ended June 30, 2011, as compared to $101.5 million, or $1.03 per diluted share, during the same period in 2010. Included in net income attributable to OGE Energy during the six months ended June 30, 2010 was a one-time, non-cash charge of $11.4 million, or $0.11 per diluted share, 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). The increase in net income attributable to OGE Energy of $26.3 million, or 25.9 percent, or $0.26 per diluted share, during the six months ended June 30, 2011 as compared to the same period in 2010 was primarily due to:

• an increase in net income at OG&E of $23.8 million, or 38.9 percent, or $0.24 per diluted share of the Company's common stock, primarily due to a higher gross margin primarily from the implementation of rate riders and warmer weather in OG&E's service territory, higher allowance for equity funds used during construction and lower income tax expense related to the Medicare Part D subsidy discussed above partially offset by higher other operation and maintenance expense, higher depreciation and amortization expense and higher interest expense;

• a decrease in net income at Enogex of $2.2 million, or 4.8 percent, or $0.03 per diluted share of the Company's common stock, primarily due to higher operation and maintenance expense and the equity sale of a membership interest in Enogex Holdings to the ArcLight group partially offset by a higher gross margin primarily from higher NGL prices, the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets, lower interest expense and lower income tax expense related to the Medicare Part D subsidy discussed above; and

• an increase in net income at OGE Energy of $4.7 million, or 82.5 percent, or $0.05 per diluted share of the Company's common stock, primarily due to higher income tax benefit related to the Medicare Part D subsidy discussed above.

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Recent Developments and Regulatory Matters

OG&E 2010 Arkansas Rate Case Filing

On September 28, 2010, OG&E 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. OG&E 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-OG&E transmission owners throughout the SPP that have been allocated to OG&E 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 OG&E 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 OG&E 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 OG&E'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.

OG&E Smart Grid Project

As previously reported in the Company's 2010 Form 10-K, on December 17, 2010, OG&E 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, OG&E reached a settlement agreement with all the parties to the APSC consideration of OG&E'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. OG&E 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 OG&E 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) OG&E 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 OG&E'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 OG&E's next general rate case. OG&E 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.

OG&E 2011 Oklahoma Rate Case Filing

As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E 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, OG&E 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. OG&E expects to receive an order from the OCC in early 2012.

Enogex Sale of Harrah Processing Plant and Certain Gathering Assets

On April 1, 2011, Enogex completed the sale of its Harrah processing plant (38 MMcf/d of capacity) and the associated Wellston and Davenport gathering assets.  The proceeds from the sale were $15.9 million and Enogex recorded a pre-tax gain in the second quarter of 2011 of $3.7 million. 

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Enogex Cox City Plant Fire

As previously reported, on December 8, 2010, a fire occurred at Enogex's Cox City natural gas processing plant destroying major components of one of the four processing trains, representing 120 MMcf/d of the total 180 MMcf/d of capacity, at that facility. Gas volumes normally processed at the Cox City plant were diverted to other facilities or bypassed around Enogex's system to accommodate production and all of the impacted gathered volumes were back online in December 2010.   The damaged train is being replaced and the facility is expected to return to full service during the third quarter of 2011. Enogex currently estimates the total costs necessary to return the facility back to full service at approximately $30 million. While Enogex believes that the costs in excess of the $10 million deductible should be reimbursed by insurance, the matter is currently being negotiated with the insurance company and Enogex cannot predict the precise outcome of these negotiations or the timing associated with the recovery. Although Enogex currently expects reimbursement of at least a portion of the costs in 2011, it is possible that some amounts may not be received until 2012.  Enogex will recognize insurance recoveries in earnings as the insurance claims are resolved.

Enogex Western Oklahoma / Texas Panhandle Expansions

In support of significant long-term acreage dedications from its customers in the area, Enogex continues to expand its gathering infrastructure in four counties of western Oklahoma. These expansions are planned to occur in phases, with the initial phase calling for the installation of 118,000 horsepower of low pressure compression and over 440 miles of gathering pipe across the area. This infrastructure is expected to be constructed throughout 2012. The capital expenditures associated with these expansions projects are expected to be $425 million.

Enogex Transportation System Expansion

In August 2010, Enogex completed construction of transportation and compression facilities necessary to provide gas delivery service to a new natural gas-fired electric generation facility near Pryor, Oklahoma. Aid in construction payments of $36.4 million received in excess of construction costs were recognized as Deferred Revenues on the Company's Consolidated Balance Sheet and are being amortized on a straight-line basis of $1.2 million per year over the life of the related Firm Transportation Service Agreement under which service commenced in June 2011.

2011 Outlook

The Company currently projects that it will exceed the top end of its previously disclosed 2011 earnings guidance of between $299 million and $318 million of net income, or $3.00 to $3.20 per average diluted share.  The primary driver for the increase is a higher gross margin at OG&E 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 March 31, 2011. These assumptions include normal weather in OG&E's service territory for the remainder of the year and, if Enogex is successful in negotiating renewals and extensions of the gathering and processing contracts with one of its five largest customers that would, among other things, change the processing arrangement from keep-whole to fixed-fee, then Enogex would be expected to be at the lower end of its 2011 earnings guidance range of $0.90 to $1.05 of earnings per average diluted share.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the three and six months ended June 30, 2011 as compared to the same periods in 2010 and the Company's consolidated 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 Consolidated Financial Statements and Notes thereto.  Known trends and contingencies of a material nature are discussed to the extent considered relevant.

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions, except per share data)	2011		2010		2011		2010
Operating income	$	182.2	$	151.5	$	250.1	$	238.3
Net income attributable to OGE Energy	$	103.0	$	77.3	$	127.8	$	101.5
Basic average common shares outstanding	98.0		97.3		97.8		97.2
Diluted average common shares outstanding	99.3		98.7		99.2		98.6
Basic earnings per average common share attributable to
OGE Energy common shareholders	$	1.05	$	0.79	$	1.31	$	1.04
Diluted earnings per average common share attributable to
OGE Energy common shareholders	$	1.04	$	0.78	$	1.29	$	1.03
Dividends declared per common share	$	0.3750	$	0.3625	$	0.7500	$	0.7250

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

Operating Income (Loss) by Business Segment

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011			2010			2011			2010
OG&E (Electric Utility)	$	133.3		$	113.0		$	159.3		$	144.9
Enogex (Natural Gas Midstream Operations)
Transportation and storage	16.4			14.8			33.8			39.4
Gathering and processing	36.8			29.2			65.0			61.5
Marketing (A)	(4.1		)	(6.0		)	(7.6		)	(7.5		)
Other Operations (B)	(0.2		)	0.5			(0.4		)	—
Consolidated operating income	$	182.2		$	151.5		$	250.1		$	238.3

(A) On November 1, 2010, OGE Energy distributed the equity interests in OER to Enogex LLC. Accordingly, the results of OER are included in Enogex's results for all periods presented.

(B) Other Operations primarily includes the operations of the holding company and consolidating eliminations.

The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements. 

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OG&E (Electric Utility)

	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

OG&E'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 OG&E'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 OG&E's service territory, which increased the gross margin by $3.5 million.

Cost of goods sold for OG&E 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. OG&E'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 OG&E'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 OG&E 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 OG&E'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

OG&E'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 OG&E's service territory, which increased the gross margin by $14.7 million;

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

• higher demand and related revenues by non-residential customers in OG&E'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 OG&E 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 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

36

generation partially offset by higher coal prices and higher coal generation. OG&E'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 OG&E'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 OG&E'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 related to the fuel over recovery balance.

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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.

Enogex (Natural Gas Midstream Operations)

	Transportation		Gathering
Three Months Ended	and		and
June 30, 2011	Storage		Processing		Marketing			Eliminations			Total
(In millions)
Operating revenues	$	108.0	$	289.1	$	168.3		$	(135.3	)	$	430.1
Cost of goods sold	69.5		210.9		170.4			(134.4		)	316.4
Gross margin on revenues	38.5		78.2		(2.1		)	(0.9		)	113.7
Other operation and maintenance	13.0		26.3		2.0			(0.7		)	40.6
Depreciation and amortization	5.8		13.4		0.1			—			19.3
Taxes other than income	3.3		1.7		(0.1		)	—			4.9
Operating income (loss)	$	16.4	$	36.8	$	(4.1	)	$	(0.2	)	$	48.9

	Transportation		Gathering
Three Months Ended	and		and
June 30, 2010	Storage		Processing		Marketing			Eliminations			Total
(In millions)
Operating revenues	$	97.1	$	235.4	$	189.0		$	(124.0	)	$	397.5
Cost of goods sold	60.9		168.6		192.9			(123.6		)	298.8
Gross margin on revenues	36.2		66.8		(3.9		)	(0.4		)	98.7
Other operation and maintenance	12.6		23.5		2.1			(0.9		)	37.3
Depreciation and amortization	5.4		12.5		—			—			17.9
Taxes other than income	3.4		1.6		—			—			5.0
Operating income (loss)	$	14.8	$	29.2	$	(6.0	)	$	0.5		$	38.5

	Transportation		Gathering
Six Months Ended	and		and
June 30, 2011	Storage		Processing		Marketing			Eliminations			Total
(In millions)
Operating revenues	$	208.2	$	555.8	$	366.4		$	(257.9	)	$	872.5
Cost of goods sold	133.5		407.2		369.7			(255.7		)	654.7
Gross margin on revenues	74.7		148.6		(3.3		)	(2.2		)	217.8
Other operation and maintenance	22.1		53.1		4.1			(1.5		)	77.8
Depreciation and amortization	11.2		26.9		0.1			—			38.2
Taxes other than income	7.6		3.6		0.1			—			11.3
Operating income (loss)	$	33.8	$	65.0	$	(7.6	)	$	(0.7	)	$	90.5

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	Transportation		Gathering
Six Months Ended	and		and
June 30, 2010	Storage		Processing		Marketing			Eliminations			Total
(In millions)
Operating revenues	$	208.2	$	483.3	$	434.7		$	(268.6	)	$	857.6
Cost of goods sold	127.1		348.6		437.2			(268.6		)	644.3
Gross margin on revenues	81.1		134.7		(2.5		)	—			213.3
Other operation and maintenance	23.6		44.8		4.8			(2.1		)	71.1
Depreciation and amortization	10.8		24.9		—			—			35.7
Taxes other than income	7.3		3.5		0.2			—			11.0
Operating income (loss)	$	39.4	$	61.5	$	(7.5	)	$	2.1		$	95.5

Operating Data

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Gathered volumes – TBtu/d (A)	1.36		1.33		1.33		1.30
Incremental transportation volumes – TBtu/d (B)	0.53		0.41		0.51		0.44
Total throughput volumes – TBtu/d	1.89		1.74		1.84		1.74
Natural gas processed – TBtu/d	0.76		0.83		0.76		0.78
NGLs sold (keep-whole) – million gallons	42		50		84		92
NGLs sold (purchased for resale) – million gallons	112		121		224		220
NGLs sold (percent-of-liquids) – million gallons	7		8		14		15
Total NGLs sold – million gallons	161		179		322		327
Average NGLs sales price per gallon	$	1.24	$	0.86	$	1.17	$	0.94
Average natural gas sales price per million British thermal unit	$	4.36	$	4.01	$	4.25	$	4.65

(A) Trillion British thermal units per day.

(B) Incremental transportation volumes consist of natural gas moved only on the transportation pipeline.

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

Operating Income

Enogex’s operating income increased $10.4 million, or 27.0 percent, during the three months ended June 30, 2011 as compared to the same period in 2010.  This increase was primarily due to higher average natural gas prices, higher NGLs prices and increased gathered volumes associated with expansion projects partially offset by decreased inlet processing volumes due to the 120 MMcf/d Cox City natural gas processing plant being out of service due to the fire in December 2010 and the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011.  In the normal course of Enogex’s business, the operation of its gathering, processing and transportation assets results in the creation of physical natural gas long/short positions. These physical positions can result from gas imbalances, actual versus contractual settlement differences, fuel tracker obligations and natural gas received in-kind for compensation or reimbursements.  Enogex actively manages its monthly net position through either selling excess gas or purchasing additional gas needs from third parties through OER.  During the three months ended June 30, 2011, volume changes and realized margin on physical gas long/short positions decreased the gross margin by $1.7 million, net of corresponding imbalance and fuel tracker obligations.

Other operation and maintenance expense increased $3.3 million, or 8.8 percent, primarily due to an increase in payroll and benefits expense and contract professional services allocated from the holding company and increased payroll and benefits costs due to increased headcount to support business growth.

Transportation and Storage

The transportation and storage business contributed $38.5 million of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to $36.2 million in the same period in 2010, an increase of $2.3 million, or 6.4 percent.  The transportation operations contributed $31.0 million of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to $30.6 million in the same period in 2010.  The storage operations contributed $7.5 million of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to $5.6 million in the same period in 2010.

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The transportation and storage gross margin increased primarily due to:

• realized losses on operational storage hedges during the three months ended June 30, 2010, which decreased the gross margin during the three months ended June 30, 2010 by $1.7 million.  There was no comparable activity during the three months ended June 30, 2011;

• higher capacity lease services under the MEP and Gulf Crossing capacity leases during the three months ended June 30, 2011 due to a reduction in the gross margin associated with these services during the three months ended June 30, 2010 as a result of pipeline integrity work on an Enogex pipeline in 2010, which increased the gross margin by $1.2 million; and

• higher firm 311 services due to a new contract and contracts with more favorable rates during the three months ended June 30, 2011, which increased the gross margin by $1.0 million.

These increases to the gross margin were partially offset by lower volumes and realized margin on sales of physical natural gas long/short positions associated with transportation operations during the three months ended June 30, 2011, which decreased the gross margin by $1.2 million, net of imbalance and fuel tracker obligations.

Gathering and Processing

The gathering and processing business contributed $78.2 million of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to $66.8 million in the same period in 2010, an increase of $11.4 million, or 17.1 percent. The gathering operations contributed $29.9 million of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to $29.1 million in the same period in 2010.  The processing operations contributed $48.3 million of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to $37.7 million in the same period in 2010.

During the three months ended June 30, 2011, Enogex realized a higher gross margin in its gathering and processing operations primarily as the result of higher NGLs prices and higher average natural gas prices.  Enogex's processing plants saw a decrease in inlet volumes as a result of the 120 MMcf/d Cox City natural gas processing plant being out of service due to the fire in December 2010 and the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011. This decrease was partially offset by an increase in volumes from recent expansion projects, primarily in the Granite Wash play and Cana/Woodford Shale play, which has added richer natural gas to Enogex's system.   Overall, the above factors resulted in an increased gross margin on keep-whole processing of $5.6 million and on percent-of-liquids contracts of $1.7 million.

Other factors that contributed to the increase in the gathering and processing gross margin were:

• an increase in condensate revenues associated with higher condensate prices and volumes, which increased the gross margin by $3.9 million; and

• increased gathered volumes associated with expansion projects, which increased the gross margin by $1.3 million.

Other operation and maintenance expense for the gathering and processing business was $2.8 million, or 11.9 percent, higher during the three months ended June 30, 2011 as compared to the same period in 2010 primarily due to an increase in payroll and benefits expense and contract professional services allocated from the holding company and increased payroll and benefits costs due to increased headcount to support business growth.

Marketing

The marketing business recognized a loss of $2.1 million as part of Enogex's consolidated gross margin during the three months ended June 30, 2011 as compared to a loss of $3.9 million in the same period in 2010, an increase in the gross margin of $1.8 million, or 46.2 percent. The marketing gross margin improved primarily due to lower realized losses during the three months ended June 30, 2011 on transportation contracts as a result of a slight improvement in the natural gas price spreads between various markets and the expiration of a transportation contract, which improved the gross margin by $0.9 million.

Enogex Consolidated Information

Other Income.  Enogex's consolidated other income was $3.8 million during the three months ended June 30, 2011 as compared to $0.1 million during the same period in 2010, an increase of $3.7 million, due to the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets.

Interest Expense.  Enogex's consolidated interest expense was $5.7 million during the three months ended June 30, 2011 as compared to $7.4 million during the same period in 2010, a decrease of $1.7 million, or 23.0 percent, primarily due to an increase

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of $1.4 million in capitalized interest related to increased construction activity during the three months ended June 30, 2011. 

Income Tax Expense.  Enogex's consolidated income tax expense was $15.5 million during the three months ended June 30, 2011 as compared to $11.9 million during the same period in 2010, an increase of $3.6 million, or 30.3 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.

Noncontrolling Interest.  Enogex's net income attributable to noncontrolling interest was $6.4 million during the three months ended June 30, 2011 as compared to $0.6 million during the same period in 2010, an increase of $5.8 million, due to the equity sale of a membership interest in Enogex Holdings to the ArcLight group.

Non-Recurring Item. During the three months ended June 30, 2011, Enogex had an increase in net income of $2.3 million relating to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011, which Enogex does not consider to be reflective of its ongoing performance.

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

Operating Income

Enogex’s operating income decreased $5.0 million, or 5.2 percent, during the six months ended June 30, 2011 as compared to the same period in 2010.  This decrease was primarily due to higher other operation and maintenance expense, higher depreciation and amortization expense, lower average natural gas prices and decreased inlet processing volumes due to the 120 MMcf/d Cox City natural gas processing plant being out of service due to the fire in December 2010 partially offset by higher NGLs prices, increased gathered volumes associated with expansion projects and the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011.  In the normal course of Enogex's business, the operation of its gathering, processing and transportation assets results in the creation of physical natural gas long/short positions. These physical positions can result from gas imbalances, actual versus contractual settlement differences, fuel tracker obligations and natural gas received in-kind for compensation or reimbursements.  Enogex actively manages its monthly net position through either selling excess gas or purchasing additional gas needs from third parties through OER.  During the six months ended June 30, 2011, volume changes and realized margin on physical gas long/short positions decreased the gross margin by $11.8 million, net of corresponding imbalance and fuel tracker obligations and the impact of the recovery of prior years' under-recovered fuel positions during the six months ended June 30, 2010.

Other operation and maintenance expense increased $6.7 million, or 9.4 percent, primarily due to an increase in payroll and benefits expense and contract professional services allocated from the holding company, increased payroll and benefits costs due to increased headcount to support business growth, higher incentive compensation and higher costs due to remediation projects during the six months ended June 30, 2011.

Transportation and Storage

The transportation and storage business contributed $74.7 million of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to $81.1 million in the same period in 2010, a decrease of $6.4 million, or 7.9 percent. The transportation operations contributed $59.1 million of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to $64.3 million in the same period in 2010.  The storage operations contributed $15.6 million of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to $16.8 million in the same period in 2010. The transportation and storage gross margin decreased primarily due to lower volumes and realized margin on sales of physical natural gas long/short positions associated with transportation operations during the six months ended June 30, 2011. Gross margin during the six months ended June 30, 2011 included the under recovery of fuel positions as compared to the six months ended June 30, 2010 that included the recovery of prior year's under-recovered fuel positions, which reduced the gross margin in 2011 by $7.9 million, net of imbalance and fuel tracker obligations. This decrease was partially offset by:

• higher firm 311 services due to a new contract and contracts with more favorable rates during the six months ended June 30, 2011, which increased the gross margin by $1.6 million; and

• higher capacity lease services under the MEP and Gulf Crossing capacity leases during the six months ended June 30, 2011 due to a reduction in the gross margin associated with these services during the six months ended June 30, 2010 as the result of pipeline integrity work on an Enogex pipeline in 2010, which increased the gross margin by $1.1 million.

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Other operation and maintenance expense for the transportation and storage business was $1.5 million, or 6.4 percent, lower during the six months ended June 30, 2011 as compared to the same period in 2010 primarily due to lower allocations from the holding company partially offset by increased payroll and benefits costs due to increased headcount to support business growth and higher incentive compensation.

Gathering and Processing

The gathering and processing business contributed $148.6 million of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to $134.7 million in the same period in 2010, an increase of $13.9 million, or 10.3 percent. The gathering operations contributed $58.3 million of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to $59.2 million in the same period in 2010.  The processing operations contributed $90.3 million of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to $75.5 million in the same period in 2010.

During the six months ended June 30, 2011, Enogex realized a higher gross margin in its gathering and processing operations primarily as the result of continued growth in gathered volumes from recent expansion projects, primarily in the Granite Wash play and Cana/Woodford Shale play, which have added richer natural gas to Enogex's system, and higher NGLs prices. These increases were partially offset by lower average natural gas prices a decrease in inlet volumes as a result of the 120 MMcf/d Cox City natural gas processing plant being out of service due to the fire in December 2010 and the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011. Overall, the above factors resulted in an increased gross margin on keep-whole processing of $6.6 million and on percent-of-liquids contracts of $1.5 million.

Other factors that contributed to the increase in the gathering and processing gross margin were:

• an increase in condensate revenues associated with higher condensate prices and volumes, which increased the gross margin by $7.6 million; and

• increased gathered volumes associated with expansion projects, which increased the gross margin by $3.1 million.

These increases in the gathering and processing gross margin were partially offset by:

• lower volumes and realized margin on sales of physical natural gas long/short positions associated with gathering operations which reduced the gross margin in 2011 by $3.9 million, net of imbalance and fuel tracker obligations; and

• lower residue gas sales as the result of lower average natural gas prices and lower gathered volumes from the Atoka area, which decreased the gross margin by $1.2 million.

Other operation and maintenance expense for the gathering and processing business was $8.3 million, or 18.5 percent, higher during the six months ended June 30, 2011 as compared to the same period in 2010 primarily due to an increase in payroll and benefits expense and contract professional services allocated from the holding company, increased payroll and benefits costs due to increased headcount to support business growth and higher costs due to remediation projects conducted during the six months ended June 30, 2011.

Marketing

The marketing business recognized a loss of $3.3 million as part of Enogex's consolidated gross margin during the six months ended June 30, 2011 as compared to a loss of $2.5 million in the same period in 2010, a decrease in the gross margin of $0.8 million, or 32.0 percent. The marketing gross margin decreased primarily due to lower margins from withdrawals from storage during the six months ended June 30, 2011 as compared to the same period in 2010, which decreased the gross margin by $3.3 million. This decrease in the marketing gross margin was partially offset by lower realized losses during the six months ended June 30, 2011 on transportation contracts as a result of a slight improvement on the natural gas price spreads between various markets and the expiration of a transportation contract, which improved the gross margin by $1.3 million.

Enogex Consolidated Information

Other Income.  Enogex's consolidated other income was $4.0 million during the six months ended June 30, 2011 as compared to $0.1 million during the same period in 2010, an increase of $3.9 million, primarily due to the recognition of a gain related to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets.

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Interest Expense.  Enogex's consolidated interest expense was $12.1 million during the six months ended June 30, 2011 as compared to $15.9 million during the same period in 2010, a decrease of $3.8 million, or 23.9 percent, primarily due to:

• an increase of $2.4 million in capitalized interest related to increased construction activity during the six months ended June 30, 2011; and

• a decrease of $1.0 million in interest expense during the six months ended June 30, 2011 due to the retirement of long-term debt in January 2010.

Income Tax Expense.  Enogex's consolidated income tax expense was $26.9 million during the six months ended June 30, 2011 as compared to $32.0 million during the same period in 2010, a decrease of $5.1 million, or 15.9 percent.  The decrease in income tax expense was primarily due to:

• lower pre-tax income during the six months ended June 30, 2011 as compared to the same period in 2010; and

• 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.

Noncontrolling Interest.  Enogex's net income attributable to noncontrolling interest was $11.2 million during the six months ended June 30, 2011 as compared to $1.6 million during the same period in 2010, an increase of $9.6 million, due to the equity sale of a membership interest in Enogex Holdings to the ArcLight group.

Non-Recurring Item. During the six months ended June 30, 2011, Enogex had an increase in net income of $2.3 million relating to the sale of the Harrah processing plant and the associated Wellston and Davenport gathering assets in April 2011, which Enogex does not consider to be reflective of its ongoing performance.

Financial Condition

The balance of Accounts Receivable was $324.9 million and $277.9 million at June 30, 2011 and December 31, 2010, respectively, an increase of $47.0 million, or 16.9 percent, primarily due to an increase in billings to OG&E's customers reflecting warmer weather in June 2011 as compared to December 2010 primarily due to higher usage by OG&E's customers and higher seasonal electric rates and an increase at Enogex due to the timing of customer payments received and higher average natural gas sales prices.

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 OG&E's customers and higher seasonal electric rates.

The balance of Fuel Inventories was $122.8 million and $158.8 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $36.0 million, or 22.7 percent, primarily due to lower coal inventory balances at OG&E 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 OG&E's cost of fuel. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E 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 OG&E to amortize under and over recovery balances.

The balance of Construction Work in Progress was $774.8 million and $460.0 million at June 30, 2011 and December 31, 2010, respectively, an increase of $314.8 million, or 68.4 percent, primarily due to increased spending on various transmission projects and Crossroads at OG&E and gathering and processing expansion projects at Enogex.

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 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).

The balance of Short-Term Debt was $211.1 million and $145.0 million at June 30, 2011 and December 31, 2010, respectively, an increase of $66.1 million, or 45.6 percent, primarily due to an increase in commercial paper borrowings during the six months ended June 30, 2011 for dividend and bond interest payments, capital expenditures for various transmission projects and Crossroads at OG&E and gathering and processing expansion projects at Enogex and daily operational needs partially offset

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by proceeds received from the contribution from the ArcLight group in February 2011 and the equity sale of a 0.1 percent membership interest in Enogex Holdings to the ArcLight group in February 2011, a portion of which were used to repay outstanding commercial paper borrowings.

The balance of Accounts Payable was $372.5 million and $321.7 million at June 30, 2011 and December 31, 2010, respectively, an increase of $50.8 million, or 15.8 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 OG&E's cost of fuel. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E 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 OG&E to amortize under and over recovery balances.

The balance of Other Current Liabilities was $71.7 million and $55.1 million at June 30, 2011 and December 31, 2010, respectively, an increase of $16.6 million, or 30.1 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 $2,586.8 million and $2,362.9 million at June 30, 2011 and December 31, 2010, respectively, an increase of $223.9 million, or 9.5 percent, due to the issuance of $250 million of long-term debt in May 2011 partially offset by repayments of borrowings under Enogex LLC's revolving credit agreement.

The balance of Accrued Benefit Obligations was $249.0 million and $372.4 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $123.4 million, or 33.1 percent, primarily due 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) 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.

The balance of Accumulated Other Comprehensive Loss was $41.8 million and $60.2 million at June 30, 2011 and December 31, 2010, respectively, a decrease of $18.4 million, or 30.6 percent, primarily due 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) and NGLs hedges being realized during the six months ended June 30, 2011.

The balance of Noncontrolling Interests was $160.6 million and $110.4 million at June 30, 2011 and December 31, 2010, respectively, an increase of $50.2 million, or 45.5 percent, primarily due to the contribution from the ArcLight group in February 2011 and the equity sale of a 0.1 percent membership interest in Enogex Holdings to the ArcLight group in February 2011 partially offset by distributions to the ArcLight group during the six months ended June 30, 2011.

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.

OG&E Railcar Lease Agreement

OG&E has a noncancellable operating lease with purchase options, covering 1,446 coal hopper railcars to transport coal from Wyoming to OG&E's coal-fired generation units.  Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011.  At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease.  If OG&E 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, OG&E would be responsible for the difference in those values up to a maximum of $23.7 million.

On February 10, 2009, OG&E 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

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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.

OG&E 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.

Liquidity and Capital Resources

Cash Flows

	Six Months Ended
	June 30,
(In millions)	2011			2010
Net cash provided from operating activities	$	246.5		$	341.5
Net cash used in investing activities	(532.7		)	(291.6		)
Net cash provided from (used in) financing activities	289.0			(100.7		)

The decrease of $95.0 million, or 27.8 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 at OG&E 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 at OG&E.

The increase of $241.1 million, or 82.7 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 at OG&E and gathering and processing expansion projects at Enogex partially offset by capital expenditures in 2010 related to the Windspeed transmission line.

The increase of $389.7 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:

• repayment of the remaining balance of Enogex LLC's $400 million 8.125% senior notes which matured on January 15, 2010;

• an increase in short-term debt borrowings during the six months ended June 30, 2011 as compared to the same period in 2010;

• contributions from the noncontrolling interest partners during the six months ended June 30, 2011; and

• a decrease in repayments of borrowings under Enogex LLC's revolving credit agreement during the six months ended June 30, 2011 as compared to the same period in 2010.

These increases in net cash provided from financing activities were partially offset by lower borrowings under Enogex LLC's revolving credit agreement during the six months ended June 30, 2011.

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 at OG&E and Enogex.  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 and commercial paper) and permanent financings.

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Capital Expenditures

The Company’s consolidated 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 businesses) plus capital expenditures for known and committed projects.

(In millions)	2011		2012		2013		2014		2015		2016
OG&E Base Transmission	$	50	$	50	$	40	$	40	$	40	$	40
OG&E Base Distribution	215		200		200		200		200		200
OG&E Base Generation	105		80		70		70		70		70
OG&E Other	35		30		30		30		30		30
Total OG&E Base Transmission, Distribution,
Generation and Other	405		360		340		340		340		340
OG&E 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 OG&E Known and Committed Projects	525		325		395		175		10		10
Total OG&E (B)	930		685		735		515		350		350
Enogex LLC Base Maintenance	75		50		55		60		60		65
Enogex LLC Known and Committed Projects:
Western Oklahoma / Texas Panhandle
Gathering Expansion	300		310		185		80		30		10
Other Gathering Expansion	30		25		25		25		25		25
Total Enogex LLC Known and Committed
Projects	330		335		210		105		55		35
Total Enogex LLC (C)	405		385		265		165		115		100
OGE Energy	20		25		25		25		25		25
Total capital expenditures	$	1,355	$	1,095	$	1,025	$	705	$	490	$	475

(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, OG&E 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.

(C) These capital expenditures represent 100 percent of Enogex LLC's capital expenditures, of which a portion will be funded by the ArcLight group.  Until the ArcLight group owns 50 percent of the equity of Enogex Holdings, the ArcLight group will fund capital contributions in an amount higher than its proportionate interest.  Specifically, the ArcLight group will fund between 50 percent and 90 percent of required capital contributions during that period.  The remainder of the required capital contributions (i.e., between 10 percent and 50 percent) will be funded by OGE Holdings.

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets and at Enogex LLC, will be evaluated based upon their impact upon achieving the Company's financial objectives.  The capital expenditure projections related to Enogex LLC in the table above reflect base market conditions at August 4, 2011 and do not reflect the potential opportunity for a set of growth projects that could materialize.

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Pension Plan Funding

The Company previously disclosed in its 2010 Form 10-K that it may contribute up to $50 million to its Pension Plan during 2011.  During the six months ended June 30, 2011, the Company contributed $40 million to its Pension Plan and 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.

Security Ratings

Access to reasonably priced capital is dependent in part on credit and security ratings. Pricing grids associated with 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 the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations.  Any future downgrade 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.  In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, at June 30, 2011, the Company would have been required to post $13.8 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at June 30, 2011.  In addition, the Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and proceeds from the sales of common stock to the public through the Company'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.  Additionally, the Company will have an additional source of funding for growth opportunities at Enogex through the ArcLight group and from quarterly distributions from Enogex Holdings. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-Term Debt and Credit Facilities

Short-term borrowings generally are used to meet working capital requirements.  The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.  The short-term debt balance was $211.1 million and $145.0 million at June 30, 2011 and December 31, 2010, respectively.  The weighted-average interest rate on short-term debt at June 30, 2011 was 0.34 percent.  The maximum month-end balance of short-term debt during the three months ended June 30, 2011 was $323.0 million. Enogex had $25.0 million in outstanding borrowings under its revolving credit agreement at December 31, 2010 with no outstanding borrowings at June 30, 2011.  As Enogex LLC's credit agreement matures on March 31, 2013, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Condensed Consolidated Balance Sheets.  At June 30, 2011, the Company had $1,021.7 million of net available liquidity under its revolving credit agreements.  Also, OG&E 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.  At June 30, 2011, the Company had $5.1 million in cash and cash equivalents.  See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

OG&E Issuance of New Long-Term Debt

On May 24, 2011, OG&E 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. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis.  In preparing the Condensed Consolidated 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 Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could

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have a material effect on the Company's Condensed Consolidated 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 are in the valuation of Pension Plan assumptions, impairment estimates, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues for OG&E, operating revenues for Enogex, natural gas purchases for Enogex, the allowance for uncollectible accounts receivable and the valuation of purchase and sale contracts.  The selection, application and disclosure of the Company's critical accounting estimates have been discussed with the Company'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 Consolidated 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 consolidated financial position, results of operations or cash flows.  See Notes 14 and 15 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q and Notes 14 and 15 of Notes to Consolidated 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 OG&E and Enogex 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 OG&E's and Enogex's business activities in many ways, such as restricting the way they can handle or dispose of their wastes, requiring remedial action to mitigate pollution conditions that may be caused by their 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.  OG&E 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.  OG&E 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 OG&E that established BART for SO2 control at four coal-fired units located at OG&E'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 OG&E.  In its place, the EPA has proposed that OG&E meet an SO2 emission rate of 0.06 pounds per million British thermal unit.  OG&E could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four coal-fired generating units at OG&E's Muskogee and Sooner generating stations.  OG&E estimates that installing Dry Scrubbers on these units would cost the Company more than $1.0 billion.  On May 23, 2011, OG&E 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 OG&E with a reasonable degree of certainty.  OG&E 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 OG&E'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 OG&E and Enogex 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.  OG&E 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 OG&E'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.  OG&E 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 OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits.  The notice of violation also alleges that OG&E'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).  OG&E 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 OG&E 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, OG&E 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. OG&E 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 OG&E 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.

Except as set forth below, the market risks set forth in Part II, Item 7A of the Company's 2010 Form 10-K appropriately represent, in all material respects, the market risks affecting the Company.

Commodity Price Risk

The market risks inherent in the Company's commodity price sensitive instruments, positions and anticipated commodity transactions are the potential losses in value arising from adverse changes in the commodity prices to which the Company is exposed.  These risks can be classified as trading, which includes transactions that are entered into voluntarily to capture subsequent changes in commodity prices, or non-trading, which includes the exposure some of the Company's assets have to commodity prices.

Trading activities are conducted throughout the year subject to $2.5 million daily and monthly trading stop loss limits set by the Risk Oversight Committee.  The loss exposure from trading activities is measured primarily using value-at-risk, which estimates the potential losses the trading activities could incur over a specified time horizon and confidence level.  Currently, the Company utilizes the variance/co-variance method for calculating value-at-risk, assuming a 95 percent confidence level.  The value-at-risk limit set by the Risk Oversight Committee for the Company's trading activities is currently $1.5 million.  These limits are designed to mitigate the possibility of trading activities having a material adverse effect on the Company's operating income.

A sensitivity analysis has been prepared to estimate the Company's exposure to market risk created by trading activities.  The value of trading positions is a summation of the fair values calculated for each net commodity position based upon quoted market prices.  Market risk is estimated as the potential loss in fair value resulting from a hypothetical 20 percent adverse change in quoted market prices.  The result of this analysis, which may differ from actual results, reflects net commodity price risk to be $0.2 million at June 30, 2011.  This amount represents the Company's exposure, net of the ArcLight group's proportional share.

Commodity price risk is present in the Company's non-trading activities because changes in the prices of natural gas, NGLs and NGLs processing spreads have a direct effect on the compensation the Company receives for operating some of its assets.  These prices are subject to fluctuations resulting from changes in supply and demand.  To partially reduce non-trading commodity price risk, the Company utilizes risk mitigation tools such as default processing fees and ethane rejection capabilities to protect its downside exposure while maintaining its upside potential.  Additionally, the Company hedges, through the utilization of derivatives and other forward transactions, the effects these market fluctuations have on the Company's operating income.  Because the commodities covered by these hedges are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.

A sensitivity analysis has been prepared to estimate the Company's exposure to the commodity price risk of the Company's non-trading activities. The Company's daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries.  Quoted market prices are not available for all of the Company's non-trading positions; therefore, the value of non-trading positions is a summation of the forecasted values calculated for each commodity based upon internally generated forward price curves.  Market risk is estimated as the potential loss in fair value resulting from a hypothetical 20 percent adverse change in such prices over the next 12 months.  The result of this analysis, which may differ from actual results, reflects net commodity price risk to be $43.7 million at June 30, 2011.  This amount represents the Company's exposure, net of the ArcLight group's proportional share.

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,

50

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 or its subsidiaries and there have been no material changes in the previously reported proceedings.

1.        Opacity Notice. On May 17, 2011, OG&E entered into a Consent Order with the ODEQ related to alleged violations of Federal and state opacity standards from 2005 to present at OG&E's Muskogee and Sooner generating stations. The Consent Order requires OG&E 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 OG&E'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. OG&E 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. OG&E 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. OG&E 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 OG&E 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. OG&E 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 OG&E'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 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.

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Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

The shares indicated below represent shares of Company common stock purchased on the open market by the trustee for the Company's qualified defined contribution retirement plan and reflect shares purchased with employee contributions as well as the portion attributable to the Company's matching contributions.

				Total Number of Shares	Approximate Dollar Value of
	Total Number of	Average Price Paid		Purchased as Part of	Shares that May Yet Be
Period	Shares Purchased	per Share		Publicly Announced Plan	Purchased Under the Plan
4/1/11 – 4/30/11	43,800	$	51.62	N/A	N/A
5/1/11 – 5/31/11	44,500	$	50.73	N/A	N/A
6/1/11 – 6/30/11	—	$	—	N/A	N/A

N/A – not applicable

Item 6.  Exhibits.

Exhibit No.	Description
3.01	Copy of Restated OGE Energy Corp. Certificate of Incorporation.
4.01	Supplemental Indenture No. 12 dated as of May 15, 2011 between OG&E and UMB Bank, N.A., as trustee, creating the Senior Notes. (Filed as Exhibit 4.01 to OG&E'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 OG&E'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 OG&E'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 OG&E'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.

	OGE ENERGY CORP.
	(Registrant)
By	/s/ Scott Forbes
	Scott Forbes
	Controller and Chief Accounting Officer

August 4, 2011

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EX-3.01

Exhibit 3.01

RESTATED

CERTIFICATE OF INCORPORATION

OF OGE ENERGY CORP.

To:	Oklahoma Secretary of State
	2300 N. Lincoln Blvd., Room 101
	State Capitol Building
	Oklahoma City, Oklahoma 73105-4897

The undersigned, OGE Energy Corp., an Oklahoma corporation organized and existing under and by virtue of the Oklahoma General Corporation Act for the purpose of adopting a restated, integrated and amended certificate of incorporation, does hereby submit the following:

I.

The name of this corporation shall be "OGE Energy Corp."

II.

The address of its Registered Office in the State of Oklahoma is 321 N. Harvey Ave., in the City of Oklahoma City, County of Oklahoma and the name of its Registered Agent at such address is Ms. Patricia Horn.

III.

The purpose for which this corporation is formed is to engage in any lawful act or activity for which corporations may be organized under the general corporation law of Oklahoma.

IV.

A.AUTHORIZED CAPITAL STOCK. The total number of shares which the corporation shall have the authority to issue shall be 230,000,000 shares, of which 225,000,000 shares shall be Common Stock, par value $.01 per share, and 5,000,000 shares shall be Preferred Stock, par value $.01 per share.

B.COMMON STOCK. The Board of Directors is hereby authorized to cause shares of Common Stock, par value $.01 per share, to be issued from time to time for such consideration as may be fixed from time to time by the Board of Directors, or by way of stock split pro rata to the holders of the Common Stock. The Board of Directors may also determine the proportion of the proceeds received from the sale of such stock which shall be credited upon the books of the corporation to Capital or Capital Surplus.

Each share of the Common Stock shall be equal in all respects to every other share of the Common Stock. Subject to any special voting rights of the holders of Preferred Stock fixed by or pursuant to the provisions of Section C of this Article IV, the shares of Common Stock shall entitle the holders thereof to one vote for each share upon all matters upon which shareholders have the right to vote.

No holder of shares of Common Stock shall be entitled as such as a matter of right to subscribe for or purchase any part of any new or additional issue of stock, or securities convertible into stock, of any class whatsoever, whether now or hereafter authorized, and whether issued for cash, property, services or otherwise.

After the requirements with respect to preferential dividends on Preferred Stock (fixed by or pursuant to the provisions of Section C of this Article IV), if any, shall have been met and after the corporation shall have complied with all the requirements, if any, with respect to the setting aside of sums as sinking funds or redemption or purchase accounts (fixed by or pursuant to the provisions of Section C of this Article IV) and subject further to any other conditions which may be fixed by or pursuant to the provisions of Section C of this Article IV, then, but not otherwise, the holders of Common Stock shall be entitled to receive dividends, if any, as may be declared from time to time by the Board of Directors.

After distribution in full of the preferential amount (fixed by or pursuant to the provisions of Section C of this Article IV), if any, to be distributed to the holders of Preferred Stock in the event of voluntary or involuntary liquidation, distribution or sale of assets, dissolution or winding up of the corporation, the holders of the Common Stock shall be entitled to receive all the remaining assets of the corporation, tangible and intangible, of whatever kind available for distribution to shareholders, ratably in proportion to the number of shares of Common Stock held by each.

C.PREFERRED STOCK. Shares of Preferred Stock may be divided into and issued in such series, on such terms and for such consideration as may from time to time be determined by the Board of Directors of the corporation. Each series shall be so designated as to distinguish the shares thereof from the shares of all other series and classes. All shares of Preferred Stock shall be identical, except as to variations between different series in the relative rights and preferences as permitted or contemplated by the next succeeding sentence. Authority is hereby vested in the Board of Directors of the corporation to establish out of shares of Preferred Stock which are authorized and unissued from time to time one or more series thereof and to fix and determine the following relative rights and preferences of shares of each such series:

(1)the distinctive designation of, and the number of shares which shall constitute, the series and the "stated value" or "nominal value," if any, thereof;

2

(2)the rate or rates of dividends applicable to shares of such series, which rate or rates may be expressed in terms of a formula or other method by which such rate or rates shall be calculated from time to time, and the dividend periods, including the date or dates on which dividends are payable;

(3)the price at and the terms and conditions on which shares of such series may be redeemed;

(4)the amount payable upon shares of such series in the event of the involuntary liquidation of the corporation;

(5)the amount payable upon shares of such series in the event of the voluntary liquidation of the corporation;

(6)sinking fund provisions for the redemption or purchase of shares of such series;

(7)the terms and conditions on which shares of such series may be converted, if such shares are issued with the privilege of conversion;

(8)the voting powers, if any, of the holders of shares of the series which may, without limiting the generality of the foregoing, include (i) the right to one or less than one vote per share on any or all matters voted upon by the shareholders and (ii) the right to vote, as a series by itself or together with other series of Preferred Stock or together with all series of Preferred Stock as a class, upon such matters, under such circumstances and upon such conditions as the Board of Directors may fix, including, without limitation, the right, voting as a series by itself or together with other series of Preferred Stock or together with all series of Preferred Stock as a class, to elect one or more directors of this corporation in the event there shall have been a failure to pay dividends on any one or more series of Preferred Stock or under such other circumstances and upon such conditions as the Board of Directors may determine; provided, however, that in no event shall a share of Preferred Stock have more than one vote; and

(9)any other such rights and preferences as are not inconsistent with the Oklahoma General Corporation Act.

No holder of any share of any series of Preferred Stock shall be entitled to vote for the election of directors or in respect of any other matter except as may be required by the Oklahoma General Corporation Act, as amended, or as is permitted by the resolution or resolutions adopted by the Board of Directors authorizing the issue of such series of Preferred Stock.

D.OTHER PROVISIONS

(1)The relative powers, preferences, and rights of each series of Preferred Stock in relation to the powers, preferences and rights of each other series of Preferred Stock shall, in each case, be as fixed from time to time by the Board of Directors in the resolution or resolutions adopted pursuant to authority granted in Section C of this Article IV, and the consent by class or series vote or otherwise, of the holders of the

3

Preferred Stock or such of the series of the Preferred Stock as are from time to time outstanding shall not be required for the issuance by the Board of Directors of any other series of Preferred Stock whether the powers, preferences and rights of such other series shall be fixed by the Board of Directors as senior to, or on a parity with, the powers, preferences and rights of such outstanding series, or any of them, provided, however, that the Board of Directors may provide in such resolution or resolutions adopted with respect to any series of Preferred Stock that the consent of the holders of a majority (or such greater proportion as shall be therein fixed) of the outstanding shares of such series voting thereon shall be required for the issuance of any or all other series of Preferred Stock.

(2)Subject to the provisions of paragraph 1 of this Section D, shares of any series of Preferred Stock may be issued from time to time as the Board of Directors shall determine and on such terms and for such consideration as shall be fixed by the Board of Directors.

(3)Common Stock may be issued from time to time as the Board of Directors shall determine and on such terms and for such consideration as shall be fixed by the Board of Directors.

(4)No holder of any of the shares of any class or series of shares or securities convertible into such shares of any class or series of shares, or of options, warrants or other rights to purchase or acquire shares of any class or series of shares or of other securities of the corporation shall have any preemptive right to purchase, acquire, subscribe for any unissued shares of any class or series or any additional shares of any class or series to be issued by reason of any increase of the authorized capital stock of the corporation of any class or series, or bonds, certificates of indebtedness, debentures or other securities convertible into or exchangeable for shares of any class or series, or carrying any right to purchase or acquire shares of any class or series, but any such unissued shares, additional authorized issue of shares of any class or series of shares or securities convertible into or exchangeable for shares, or carrying any right to purchase or acquire shares, may be issued and disposed of pursuant to resolution of the Board of Directors to such persons, firms, corporations or associations, and upon such terms, as may be deemed advisable by the Board of Directors in the exercise of its sole discretion.

(5)The corporation reserves the right to increase or decrease its authorized capital shares, or any class or series thereof or to reclassify the same and to amend, alter, change or repeal any provision contained in the Certificate of Incorporation or in any amendment thereto, in the manner now or hereafter prescribed by law, but subject to such conditions and limitations as are hereinbefore prescribed, and all rights conferred upon shareholders in the Certificate of Incorporation of this corporation, or any amendment thereto, are granted subject to this reservation.

V.

Reserved.

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VI.

A.VOTE REQUIRED FOR CERTAIN BUSINESS COMBINATIONS.

a.In addition to any affirmative vote required by law or this Article VI or any other Article hereof, and except as otherwise expressly provided in Section B of this Article VI:

i.any merger or consolidation of the corporation or any Subsidiary (as hereinafter defined) with (i) any Interested Shareholder (as hereinafter defined) or (ii) any other corporation (whether or not itself an Interested Shareholder) which is, or after such merger or consolidation would be, an Affiliate (as hereinafter defined) of an Interested Shareholder; or

ii.any sale, lease, exchange, mortgage, pledge, transfer or other disposition (in one transaction or a series of transactions) to or with any Interested Shareholder or any Affiliate of any Interested Shareholder of any assets of the corporation or any Subsidiary having an aggregate Fair Market Value of $25,000,000 or more; or

iii.the issuance or transfer by the corporation or any Subsidiary (in one transaction or a series of transactions) of any securities of the corporation or any Subsidiary to any Interested Shareholder or any Affiliate of any Interested Shareholder in exchange for cash, securities or other property (or a combination thereof) having an aggregate Fair Market Value of $25,000,000 or more, other than the issuance of securities upon the conversion of convertible securities of the corporation or any Subsidiary which were not acquired by such Interested Shareholder (or such Affiliate) from the corporation or a Subsidiary; or

iv.the adoption of any plan or proposal for the liquidation or dissolution of the corporation proposed by or on behalf of an Interested Shareholder or any Affiliate of any Interested Shareholder; or

v.any reclassification of securities (including any reverse stock split), or recapitalization of the corporation, or any merger or consolidation of the corporation with any of its Subsidiaries or any other transaction (whether or not with or into or otherwise involving an Interested Shareholder) which has the effect, directly or indirectly, of increasing the proportionate share of the outstanding shares of any class or series of stock or securities convertible into stock of the corporation or any Subsidiary which is directly or indirectly owned by any Interested Shareholder or any Affiliate of any Interested Shareholder;

shall require the affirmative vote of the holders of at least 80% of the voting power of the then outstanding shares of stock of the corporation entitled to vote generally in the election of directors (the "Voting Stock"), voting together as a single class (it being understood that for purposes of this Article VI, each share of the Voting Stock shall have the number of votes granted to it pursuant to Article IV hereof). Such affirmative vote shall be required notwithstanding the fact that no vote may be required, or that a lesser percentage may be

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specified, by law, by any provision hereof, or in any agreement with any national securities exchange or otherwise.

b.The term "Business Combination" as used in this Article VI shall mean any transaction which is referred to in any one or more subparagraphs (a) through (e) of paragraph 1 of this Section A.

B.WHEN HIGHER VOTE IS NOT REQUIRED. The provisions of Section A of this Article VI shall not be applicable to any particular Business Combination, and such Business Combination shall require only such affirmative vote as is required by law and any other provision of any Article hereof, if all of the conditions specified in either of the following paragraphs 1 and 2 are met:

a.The Business Combination shall have been approved by a majority of the Disinterested Directors (as hereinafter defined).

b.All of the following conditions shall have been met:

(a)The aggregate amount of the cash and the Fair Market Value (as hereinafter defined) as of the date of the consummation of the Business Combination of any consideration other than cash to be received per share by holders of Common Stock in such Business Combination shall be at least equal to the higher of the following:

I.(if applicable) the Highest Per Share Price (as hereinafter defined) (including the brokerage commissions, transfer taxes and soliciting dealers' fees) paid in order to acquire any shares of Common Stock beneficially owned by the Interested Shareholder which were acquired beneficially by such Interested Shareholder (X) within the two-year period immediately prior to the first public announcement of the proposal of the Business Combination (the "Announcement Date") or (Y) in the transaction in which it became an Interested Shareholder, whichever is higher; and

II.the Fair Market Value per share of Common Stock on the Announcement Date or on the date on which the Interested Shareholder became an Interested Shareholder (such later date is referred to in this Article VI as the "Determination Date"), whichever is higher.

(b)The aggregate amount of the cash and the Fair Market Value as of the date of the consummation of the Business Combination of consideration other than cash to be received per share by holders of shares of any class or series of outstanding Voting Stock other than the Common Stock shall be at least equal to the highest of the following (it being intended that the requirements of this subparagraph (b) shall be required to be met with respect to every such class or series of outstanding Voting Stock, whether or not the Interested Shareholder beneficially owns any shares of a particular class or series of Voting Stock):

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I.(if applicable) the Highest Per Share Price (as hereinafter defined) (including any brokerage commissions, transfer taxes and soliciting dealers' fees) paid in order to acquire any shares of such class or series of Voting Stock beneficially owned by the Interested Shareholder which were acquired beneficially by such Interested Shareholder (X) within the two-year period immediately prior to the Announcement Date or (Y) in the transaction in which it became an Interested Shareholder, whichever is higher;

II.(if applicable) the highest preferential amount per share to which the holders of shares of such class or series of Voting Stock are entitled in the event of any voluntary or involuntary liquidation, dissolution or winding up of the corporation; and

III.the Fair Market Value per share of such class or series of Voting Stock on the Announcement Date or on the Determination Date, whichever is higher.

(c)The consideration to be received by holders of a particular class or series of outstanding Voting Stock (including Common Stock) shall be in cash or in the same form as was previously paid in order to acquire beneficially shares of such class or series of Voting Stock that are beneficially owned by the Interested Shareholder and, if the Interested Shareholder beneficially owns shares of any class or series of Voting Stock that were acquired with varying forms of consideration, the form of consideration to be received by holders of such class or series of Voting Stock shall be either cash or the form used to acquire beneficially the largest number of shares of such class or series of Voting Stock beneficially acquired by it prior to the Announcement Date.

(d)After such Interested Shareholder has become an Interested Shareholder and prior to the consummation of such Business Combination: (i) except as approved by a majority of the Disinterested Directors, there shall have been no failure to declare and pay at the regular dates therefor the full amount of any dividends (whether or not cumulative) payable on any class or series of stock having a preference over the Common Stock as to dividends or upon liquidation; (ii) there shall have been (x) no reduction in the annual rate of dividends paid on the Common Stock (except as necessary to reflect any subdivision of the Common Stock), except as approved by a majority of the Disinterested Directors, and (y) an increase in such annual rate of dividends (as necessary to prevent any such reduction) in the event of any reclassification (including any reverse stock split), recapitalization, reorganization or any similar transaction which has the effect of reducing the number of outstanding shares of the Common Stock, unless the failure so to increase such annual rate was approved by a majority of the Disinterested Directors; and (iii) such Interested Shareholder shall have not become the beneficial owner of any additional shares of Voting Stock except as part of the transaction which results in such Interested Shareholder becoming an Interested Shareholder.

(e)After such Interested Shareholder has become an Interested Shareholder, such Interested Shareholder shall not have received the benefit, directly or

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indirectly (except proportionally as a stockholder), of any loans, advances, guarantees, pledges or other financial assistance or any tax credits or other tax advantages provided by the corporation, whether in anticipation of or in connection with such Business Combination or otherwise.

(f)A proxy or information statement describing the proposed Business Combination and complying with the requirements of the Securities Exchange Act of 1934 and the rules and regulations thereunder (or any subsequent provisions replacing such Act, rules or regulations) shall be mailed to public shareholders of the corporation at least 30 days prior to the consummation of such Business Combination (whether or not such proxy or information statement is required to be mailed pursuant to such Act or subsequent provisions).

C.CERTAIN DEFINITIONS. For the purposes of this Article VI:

a.A "person" shall mean any individual, firm, corporation or other entity.

b."Interested Shareholder" shall mean any person (other than the corporation or any Subsidiary) who or which:

i.is the beneficial owner, directly or indirectly of more than 10% of the voting power of the outstanding Voting Stock; or

ii.is an Affiliate of the corporation and at any time within the two-year period immediately prior to the date in question was the beneficial owner, directly or indirectly, of 10% or more of the voting power of the then outstanding Voting Stock; or

iii.is an assignee of or has otherwise succeeded to any shares of Voting Stock that were at any time within the two-year period immediately prior to the date in question beneficially owned by any Interested Stockholder, if such assignment or succession shall have occurred in the course of a transaction or series of transactions not involving a public offering within the meaning of the Securities Act of 1933.

c.A person shall be a "beneficial owner" of any Voting Stock:

i.which such person or any of its Affiliates or Associates (as hereinafter defined) beneficially owns, directly or indirectly; or

ii.which such person or any of its Affiliates or Associates has (i) the right to acquire (whether such right is exercisable immediately or only after the passage of time), pursuant to any agreement, arrangement or understanding or upon the exercise of conversion rights, exchange rights, warrants or options, or otherwise, or (ii) the right to vote or direct the vote pursuant to any agreement, arrangement or understanding; or

iii.which are beneficially owned, directly or indirectly, by any other person with which such person or any of its Affiliates or Associates has any

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agreement, arrangement or understanding for the purposes of acquiring, holding, voting or disposing of any shares of Voting Stock.

d.For the purposes of determining whether a person is an Interested Shareholder pursuant to paragraph 2 of this Section C, the number of shares of Voting Stock deemed to be outstanding shall include shares deemed owned through application of paragraph 3 of this Section C but shall not include any other shares of Voting Stock which may be issuable pursuant to any agreement, arrangement or understanding or upon exercise of conversion rights, warrants or options, or otherwise.

e."Affiliate" or "Associate" shall have the respective meanings ascribed to such terms in Rule 12b-2 of the General Rules and Regulations, under the Securities Exchange Act of 1934, as in effect on November 16, 1995.

f."Subsidiary" means any corporation of which a majority of any class of equity security is owned, directly or indirectly, by the corporation or by a Subsidiary of the corporation or by the corporation and one or more Subsidiaries; provided, however, that for the purposes of the definition of Interested Shareholder set forth in paragraph 2 of this Section C, the term "Subsidiary" shall mean only a corporation of which a majority of each class of equity security is owned, directly or indirectly, by the corporation.

g."Disinterested Director" means any member of the Board of Directors of the corporation who is unaffiliated with, and not a nominee or representative of, the Interested Shareholder and was a member of the Board of Directors prior to the time that the Interested Shareholder became an Interested Shareholder, and any successor of a Disinterested Director who is unaffiliated with, and not a nominee or representative of, the Interested Shareholder and who is recommended to succeed a Disinterested Director by a majority of Disinterested Directors then on the Board of Directors.

h."Fair Market Value" means: (a) in the case of stock, the highest closing sale price during the 30-day period immediately preceding the date in question of a share of such stock on the Composite Tape for New York Stock Exchange-Listed Stocks, or, if such stock is not quoted on the Composite Tape on the New York Stock Exchange, or, if such stock is not listed on such Exchange, on the principal United States securities exchange registered under the Securities Exchange Act of 1934 on which such stock is listed, or, if such stock is not listed on any such exchange, the highest closing sales price or bid quotation with respect to a share of such stock during the 30-day period preceding the date in question on the National Association of Securities Dealers, Inc. Automated Quotations System or any system then in use, or if no such quotations are available, the fair market value on the date in question of a share of such stock as determined by a majority of the Disinterested Directors in good faith, in each case with respect to any class of stock, appropriately adjusted for any dividend or distribution in shares of such stock or any stock split or reclassification of outstanding shares of such stock into a greater number of shares of such stock or any combination or reclassification of outstanding shares of such stock into a smaller number of shares of such stock; and (b) in the case of stock of any class or series which is not traded on any United States registered securities exchange nor in the

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over-the-counter market or in the case of property other than cash or stock, the fair market value of such property on the date in question as determined by a majority of the Disinterested Directors in good faith.

i.References to "Highest Per Share Price" shall in each instance, with respect to any class of stock, reflect an appropriate adjustment for any dividend or distribution in shares of such stock or any stock split or reclassification of outstanding shares of such stock into a greater number of shares of such stock or any combination or reclassification of outstanding shares of such stock into a smaller number of shares of such stock.

j.In the event of any Business Combination in which the corporation survives, the phrase “consideration other than cash to be received” as used in subparagraphs (a) and (b) of paragraph 2 of Section B of this Article VI shall include the shares of Common Stock and/or the shares of any other class of outstanding Voting Stock retained by the holders of such shares.

D.POWERS OF THE BOARD OF DIRECTORS. A majority of the Disinterested Directors of the corporation shall have the power and duty to determine, on the basis of information known to them after reasonable inquiry, all facts necessary to determine compliance with this Article VI, including without limitation, (a) whether a person is an Interested Shareholder, (b) the number of shares of Voting Stock beneficially owned by any person, (c) whether a person is an Affiliate or Associate of another, (d) whether the assets which are the subject of any Business Combination have, or the consideration to be received for the issuance or transfer of securities by the corporation or any Subsidiary in any Business Combination has, an aggregate Fair Market Value of $25,000,000 or more and (e) whether the requirements of Section B of this Article VI have been met.

E.NO EFFECT ON FIDUCIARY OBLIGATIONS OF INTERESTED SHAREHOLDERS. Nothing contained in this Article VI shall be construed to relieve any Interested Shareholder from any fiduciary obligation imposed by law.

F.AMENDMENT OR REPEAL. Notwithstanding any other provisions of this Article VI or of any other Article hereof, or of the By-laws of the corporation (and notwithstanding the fact that a lesser percentage may be specified from time to time by law, this Article VI, any other Article hereof, or the By-laws of the corporation), the provisions of this Article VI may not be altered, amended or repealed in any respect, nor may any provision inconsistent therewith be adopted, unless such alteration, amendment, repeal or adoption is approved by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding Voting Stock, voting together as a single class.

VII.

A.ELECTION AND TERMS OF DIRECTORS. Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV hereof relating to the rights of the holders of any class or series of stock having a preference over the Common Stock as to

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dividends or upon liquidation to elect directors under specified circumstances, the directors elected at or prior to the annual meeting of shareholders in 2010shall be classified, with respect to the time for which they severally hold office, into three classes, as nearly equal in number as possible, with each class of directors to serve for a term expiring at the annual meeting of shareholders held in the third year following the year of their election and until their successors are elected and qualified, subject to earlier death, resignation or removal. At each annual meeting of shareholders of the corporation after the annual meeting of shareholders in 2010 and except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV hereof relating to the rights of the holders of any class or series of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, the directors shall be elected for terms expiring at the next annual meeting of shareholders and until their successors are elected and qualified, subject to earlier death, resignation or removal; provided that the directors elected at or prior to the 2010 annual meeting of shareholders shall continue to serve until their terms expire. In each case, directors shall hold office until their successors are elected and qualified.

B.SHAREHOLDER NOMINATION OF DIRECTOR CANDIDATES AND INTRODUCTION OF BUSINESS. Advance notice of shareholder nominations for the election of directors, and advance notice of business to be brought by shareholders before an annual meeting of shareholders, shall be given in the manner provided in the By-laws of the corporation.

C.NEWLY CREATED DIRECTORSHIPS AND VACANCIES. Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV hereof relating to the rights of the holders of any class or series of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances: (i) newly created directorships resulting from any increase in the number of directors and any vacancies on the Board of Directors resulting from death, resignation, disqualification, removal or other cause shall be filled by the affirmative vote of a majority of the remaining directors then in office, even though less than a quorum of the Board of Directors; (ii) any director elected in accordance with the preceding clause (i) shall hold office until the next annual meeting of shareholdersand until such director's successor shall have been elected and qualified; and (iii) no decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director.

D.REMOVAL. Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV hereof relating to the rights of the holders of any class or series of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, any director may be removed from office, with or without cause, only by the affirmative vote of the holders of at least a majority of the combined voting power of the then outstanding shares of the corporation's stock entitled to vote generally, voting together as a single class. Whenever in this Article VII or in Article VIII hereof or in Article IX hereof, the phrase "the then outstanding shares of the corporation's stock entitled to vote generally" is used, such phrase shall mean each then outstanding share of Common Stock and of any other class or series of the corporation's stock that is entitled to vote generally in the election of directors and whose voting privileges are not generally restricted by any of the provisions of any Article hereof.

E.AMENDMENT OR REPEAL. Notwithstanding any other provisions of this Article VII or of any other Article hereof or of the By-laws of the corporation (and

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notwithstanding the fact that a lesser percentage may be specified from time to time by law, this Article VII, any other Article hereof, or the By-laws of the corporation), the provisions of this Article VII may not be altered, amended or repealed in any respect, nor may any provision inconsistent therewith be adopted, unless such alteration, amendment, repeal or adoption is approved by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of the corporation's stock entitled to vote generally, voting together as a single class.

VIII.

Any action required or permitted to be taken by the shareholders of the corporation must be effected at a duly called annual or special meeting of such holders and, except as otherwise mandated by Oklahoma law, may not be effected without such a meeting by any consent in writing by such holders. Except as otherwise mandated by Oklahoma law and except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV hereof relating to the rights of the holders of any class or series of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, special meetings of shareholders of the corporation may be called only by the Board of Directors pursuant to a resolution approved by a majority of the entire Board of Directors or by the President of the corporation. Notwithstanding any other provisions of this Article VIII or of any other Article hereof or of the By-laws of the corporation (and notwithstanding the fact that a lesser percentage may be specified from time to time by law, this Article VIII, any other Article hereof, or the By-laws of the corporation), the provisions of this Article VIII may not be altered amended or repealed in any respect, nor may any provision inconsistent therewith be adopted, unless such alteration, amendment, repeal or adoption is approved by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of the corporation's stock entitled to vote generally, voting together as a single class.

IX.

The Board of Directors shall have power to adopt, amend and repeal the By-laws of the corporation to the maximum extent permitted from time to time by Oklahoma law; provided, however, that any By-laws adopted by the Board of Directors under the powers conferred hereby may be amended or repealed by the Board of Directors or by the shareholders having voting power with respect thereto, except that, and notwithstanding any other provisions of this Article IX or of any other Article hereof or of the By-laws of the corporation (and notwithstanding the fact that a lesser percentage may be specified from time to time by law, this Article IX, any other Article hereof or the By-laws of the corporation), no provision of Section 1.1 of Article 1 of the By-laws, or of Section 4.2, Section 4.12 or Section 4.14 of Article IV of the By-laws, or of Section 5.2 or Section 5.3 of Article V the By-laws may be altered, amended or repealed in any respect, nor may any provision inconsistent therewith be adopted, unless such alteration, amendment, repeal or adoption is approved by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of the corporation's stock entitled to vote generally, voting together as a single class. Notwithstanding any other provisions of this Article IX or of any other Article hereof or of the By-laws of the corporation (and notwithstanding the fact that a lesser

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percentage may be specified from time to time by law, this Article IX, any other Article hereof or the By-laws of the corporation), the provisions of this Article IX may not be altered, amended or repealed in any respect, nor may any provision inconsistent therewith be adopted, unless such alteration, amendment, repeal or adoption is approved by the affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of the corporation's stock entitled to vote generally, voting together as a single class.

X.

A director of the corporation shall not be personally liable to the corporation or its shareholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to the corporation or its shareholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 1053 of the Oklahoma General Corporation Act, or (iv) for any transaction from which the director derived any improper personal benefit. If the Oklahoma General Corporation Act is amended after approval by the shareholders of this Article to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of a director of the corporation shall be eliminated or limited to the fullest extent permitted by the Oklahoma General Corporation Act, as so amended.

Any repeal or modification of the foregoing paragraph by the shareholders of the corporation shall not adversely affect any right or protection of a director of the corporation existing at the time of such repeal or modification.

XI.

A.RIGHT TO INDEMNIFICATION. Each person who was or is made a party or is threatened to be made a party to or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a "proceeding"), by reason of the fact that he or she is or was a director, officer or employee of the corporation or is or was serving at the request of the corporation as a director, officer or employee of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (hereinafter an "indemnitee"), whether the basis of such proceeding is alleged action in an official capacity as a director, officer or employee or in any other capacity while serving as a director, officer or employee, shall be indemnified and held harmless by the corporation to the fullest extent authorized by the Oklahoma General Corporation Act, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the corporation to provide broader indemnification rights than such law permitted the corporation to provide prior to such amendment), against all expense, liability and loss (including attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid in settlement) reasonably incurred or suffered by such indemnitee in connection therewith and such indemnification shall continue as to an indemnitee who had ceased to be a director, officer or employee and shall inure to the benefit of the indemnitee's heirs, executor and administrators; provided, however, that, except as provided in Section B of this Article XI with respect to proceedings to enforce rights to indemnification, the corporation shall indemnify any such

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indemnitee in connection with a proceeding (or part thereof) initiated by such indemnitee only if such proceeding (or part thereof) was authorized by the Board of Directors of the corporation. Any person who is or was a director or officer of a subsidiary of the corporation shall be deemed to be serving in such capacity at the request of the corporation for purposes of this Article XI. The right to indemnification conferred in this Article shall include the right to be paid by the corporation the expenses incurred in defending any such proceeding in advance of its final disposition (hereinafter an "advancement of expenses"); provided, however, that, if the Oklahoma General Corporation Act requires, an advancement of expenses incurred by an indemnitee in his or her capacity as a director or officer (and not in any other capacity in which service was or is rendered by such indemnitee, including, without limitation, service with respect to an employee benefit plan) shall be made only upon delivery to the corporation of an undertaking (hereinafter an "undertaking"), by or on behalf of such indemnitee, to repay all amounts so advanced if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (hereinafter, a "final adjudication") that such indemnitee is not entitled to be indemnified for such expenses under this Article or otherwise. The rights to indemnification and advancement of expenses conferred in this Section A shall be a contract right.

B.RIGHT OF INDEMNITEE TO BRING SUIT. If a claim under Section A of this Article XI is not paid in full by the corporation within sixty days after a written claim has been received by the corporation, except in the case of a claim for an advancement of expenses, in which case the applicable period shall be twenty days, the indemnitee may at any time thereafter bring suit against the corporation to recover the unpaid amount of the claim. If successful in whole or in part in any such suit or in a suit brought by the corporation to recover an advancement of expenses pursuant to the terms of an undertaking, the indemnitee also shall be entitled to be paid the expense of prosecuting or defending such suit. In (i) any suit brought by the indemnitee to enforce a right to indemnification hereunder (but not in a suit brought by the indemnitee to enforce a right to an advancement of expenses) it shall be a defense that, and in (ii) any suit by the corporation to recover an advancement of expenses pursuant to the terms of an undertaking the corporation shall be entitled to recover such expenses upon a final adjudication that, the indemnitee has not met the applicable standard of conduct set forth in the Oklahoma General Corporation Act. Neither the failure of the corporation (including its Board of Directors, independent legal counsel, or its shareholders) to have made a determination prior to the commencement of such suit that indemnification of the indemnitee is proper in the circumstances because the indemnitee has met the applicable standard of conduct set forth in the Oklahoma General Corporation Act, nor an actual determination by the corporation (including its Board of Directors, independent legal counsel, or its shareholders) that the indemnitee has not met such applicable standard of conduct, shall create a presumption that the indemnitee has not met the applicable standard of conduct or, in the case of such a suit brought by the indemnitee, be a defense to such suit. In any suit brought by the indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or by the corporation to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the indemnitee is not entitled to be indemnified or to such advancement of expenses under this Article XI or otherwise shall be on the corporation.

C.NON-EXCLUSIVITY OF RIGHTS. The rights to indemnification and to the advancement of expenses conferred in this Article XI shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, these Articles of Incorporation,

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any By-law, any agreement, any vote of shareholders or disinterested directors or otherwise.

D.INSURANCE. The corporation may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the corporation or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss, whether or not the corporation would have the power to indemnify such person against such expense, liability or loss under the Oklahoma General Corporation Act.

E.INDEMNIFICATION OF AGENTS. The corporation may, to the extent authorized from time to time by the Board of Directors, grant rights to indemnification and to the advancement of expenses to any agent of the corporation and to any person serving at the request of the corporation as an agent of another corporation or of a partnership, joint venture, trust or other enterprise to the fullest extent of the provisions of this Article XI with respect to the indemnification and advancement of expenses of directors, officers and employees of the corporation.

F.REPEAL OR MODIFICATION. Any repeal or modification of any provision of this Article XI by the shareholders of the corporation shall not adversely affect any rights to indemnification and to advancement of expenses that any person may have at the time of such repeal or modification with respect to any acts or omissions occurring prior to such repeal or modification.

XII.

Of the then allotted shares of Preferred Stock described in Article IV hereof, the Board of Directors on August 7, 1995, established a series of Preferred Stock in the amount and with the designation, voting powers, preferences and relative, participating, options or other special rights and the qualifications, limitations or restrictions as follows:

SECTION 1.DESIGNATION AND AMOUNT. The shares of such series shall be designated “Series A Preferred Stock” and the number of shares constituting such series shall be 1,250,000. Shares of Series A Preferred Stock shall have a par value of $.01 per share.

SECTION 2.DIVIDENDS AND DISTRIBUTIONS.

(A)Subject to the possible prior and superior rights of the holders of any shares of preferred stock of the Company ranking prior and superior to the shares of Series A Preferred Stock with respect to dividends, each holder of Series A Preferred Stock shall be entitled to receive, when, as and if declared by the Board of Directors out of funds legally available for that purpose: (i) quarterly dividends payable in cash on January 20, April 20, July 20 and October 20 in each year (each such date being a "Quarterly Dividend Payment Date"), commencing on the first Quarterly Dividend Payment Date after the first issuance of such share of Series A Preferred Stock, in an amount per share (rounded to the nearest cent) equal to the greater of (a) $5.00 or (b) subject to the provision for adjustment hereinafter set forth, 100 times the aggregate per share amount of all cash dividends declared on shares of the Common Stock of the Company, par value $.01 per share (the "Common Stock"), since the immediately preceding Quarterly Dividend Payment Date, or, with respect to the first Quarterly Dividend Payment Date, since the first issuance of a share of

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Series A Preferred Stock and (ii) subject to the provision for adjustment hereinafter set forth, quarterly distributions (payable in kind) on each Quarterly Dividend Payment Date in an amount per share equal to 100 times the aggregate per share amount of all non-cash dividends or other distributions (other than a dividend payable in shares of Common stock or a subdivision of the outstanding shares of Common Stock, by reclassification or otherwise) declared on shares of Common Stock since the immediately preceding Quarterly Dividend Payment Date, or with respect to the first Quarterly Dividend Payment Date, since the first issuance of a share of Series A Preferred Stock. If the quarterly Dividend Payment Date is a Saturday, Sunday or legal holiday, then such Quarterly Dividend Payment Date shall be the first immediately preceding calendar day which is not a Saturday, Sunday or legal holiday. In the event that the Company shall at any time after August 7, 1995 (the "Rights Declaration Date") (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case, the amount to which the holder of a share of Series A Preferred Stock was entitled immediately prior to such event pursuant to the preceding sentence shall be adjusted by multiplying such amount by a fraction, the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event, and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event.

(B)The Company shall declare a dividend or distribution on shares of Series A Preferred Stock as provided in paragraph A above immediately after it declares a dividend or distribution on the shares of Common Stock (other than a dividend payable in shares of Common Stock); provided, however, that, in the event no dividend or distribution shall have been declared on the Common Stock during the period between any Quarterly Dividend Payment Date and the next subsequent Quarterly Dividend Payment Date, a dividend of $5.00 per share on the Series A Preferred Stock shall nevertheless be payable on such subsequent Quarterly Dividend Payment Date.

(C)Dividends shall begin to accrue and shall be cumulative on each outstanding share of Series A Preferred Stock from the Quarterly Dividend Payment Date next preceding the date of issuance of such share of Series A Preferred Stock, unless the date of issuance of such share is prior to the record date for the first Quarterly Dividend Payment Date, in which case, dividends on such share shall begin to accrue from the date of issuance of such share, or unless the date of issuance is a Quarterly Dividend Payment Date or is a date after the record date for the determination of holders of shares of Series A Preferred Stock entitled to receive a quarterly dividend and before such Quarterly Dividend Payment Date, in either of which events such dividends shall begin to accrue and be cumulative from such Quarterly Dividend Payment Date. Accrued but unpaid dividends shall not bear interest. Dividends paid on shares of Series A Preferred Stock in an amount less than the aggregate amount of all such dividends at the time accrued and payable on such shares shall be allocated pro rata on a share-by-share basis among all shares of Series A Preferred Stock at the time outstanding. The Board of Directors may fix a record date for the determination of holders of shares of Series A Preferred Stock entitled to receive payment of a dividend or distribution declared thereon, which record date shall be no more than 60 days prior to the date fixed for the payment thereof.

16

(D)Dividends payable on the Series A Preferred Stock for the initial dividend period and for any period less than a full quarterly period, shall be computed on the basis of a 360-day year of 30-day months.

SECTION 3.VOTING RIGHTS. The holders of shares of Series A Preferred Stock shall have the following voting rights:

(A)Each share of Series A Preferred Stock shall entitle the holder thereof to one vote on all matters submitted to a vote of the shareholders of the Company.

(B)Except as otherwise provided herein or by law, the holders of shares of Series A Preferred Stock and the holders of shares of Common Stock shall vote together as one class on all matters submitted to a vote of shareholders of the Company.

(C)If at the time of any annual meeting of shareholders for the election of directors a "default in preference dividends" on the Series A Preferred Stock shall exist, the holders of the Series A Preferred Stock shall have the right at such meeting, voting together as s single class, to the exclusion of the holders of Common Stock, to elect two (2) directors of the Company. Such right shall continue until there are no dividends in arrears upon the Series A Preferred Stock. Either or both of the two directors to be elected by the holders of Series A Preferred Stock may be to fill a vacancy or vacancies created by an increase by the Board of Directors in the number of directors constituting the Board of Directors. Each director elected by the holders of Preferred Stock (a "Preferred Director") shall continue to serve as such director for the full term for which he or she shall have been elected, notwithstanding that prior to the end of such term a default in preference dividends shall cease to exist. Any Preferred Director may be removed by, and shall not be removed except by, the vote of the holders of record of the outstanding Series A Preferred Stock voting together as a single class, at a meeting of the shareholders or of the holders of Preferred Stock called for the purpose. So long as a default in preference dividends on the Series A Preferred Stock shall exist, (i) any vacancy in the office of a Preferred Director may be filled (except as provided in the following clause (ii)) by an instrument in writing signed by the remaining Preferred Director and filed with the Company and (ii) in the case of the removal of any Preferred Director, the vacancy may be filled by the vote of the holders of the outstanding Series A Preferred Stock voting together as a single class, at the same meeting at which such removal shall be voted. Each director appointed as aforesaid by the remaining Preferred Director shall be deemed, for all purposes hereof, to be a Preferred Director. For the purposes hereof, a "default in preference dividends" on the Preferred Stock shall be deemed to have occurred whenever the amount of accrued and unpaid dividends upon the Series A Preferred Stock shall be equivalent to six (6) full quarterly dividends or more, and having so occurred, such default shall be deemed to exist thereafter until, but only until, all accrued dividends on all Series A Preferred Stock then outstanding shall have been paid to the end of the last preceding quarterly dividend period. The provisions of this paragraph C shall govern the election of Directors by holders of Series A Preferred Stock during any default in preference dividends notwithstanding any provisions of the Company's Certificate of Incorporation to the contrary.

(D)Except as set forth herein, holders of shares of Series A Preferred Stock shall have no special voting rights and their consent shall not be required (except to the extent they are

17

entitled to vote with holders of shares of Common Stock as set forth herein) for taking any corporate action.

SECTION 4.CERTAIN RESTRICTIONS.

(A)Until all accrued and unpaid dividends and distributions, whether or not declared, on outstanding shares of Series A Preferred Stock shall have been paid in full, the Company shall not:

(i)declare or pay any dividends on, make any other distributions on, or redeem or purchase or otherwise acquire for consideration any shares of junior stock;

(ii)declare or pay dividends on or make any other distributions on any shares of parity stock, except dividends paid ratably on shares of Series A Preferred Stock and shares of all such parity stock on which dividends are payable or in arrears in proportion to the total amounts to which the holders of such Series A Preferred Stock and all such shares are then entitled;

(iii)redeem or purchase or otherwise acquire for consideration shares of any junior stock, provided, however, that the Company may at any time redeem, purchase or otherwise acquire shares of any such junior stock in exchange for shares of any other junior stock;

(iv)purchase or otherwise acquire for consideration any shares of Series A Preferred Stock or any shares of parity stock, except in accordance with a purchase offer made in writing or by publication (as determined by the Board of Directors) to all holders of such shares upon such terms as the Board of Directors, after consideration of the respective annual dividend rates and other relative rights and preferences of the respective series and classes, shall determine in good faith will result in fair and equitable treatment among the respective series or classes.

(B)The Company shall not permit any subsidiary of the Company to purchase or otherwise acquire for consideration any shares of stock of the Company unless the Company could, under paragraph A of this Section 4, purchase or otherwise acquire such shares at such time and in such manner.

SECTION 5.REACQUIRED SHARES. Any shares of Series A Preferred Stock purchased or otherwise acquired by the Company in any manner whatsoever shall be retired and canceled promptly after the acquisition thereof. All such shares shall upon their cancellation become authorized but unissued Preferred Stock and may be reissued as part of a new series of Preferred Stock subject to the conditions and restrictions on issuance set forth in the Certificate of Incorporation of the Company creating a series of Preferred Stock or any similar shares or as otherwise required by law.

SECTION 6.LIQUIDATION, DISSOLUTION OR WINDING UP.

(A)Upon any voluntary or involuntary liquidation, dissolution or winding up of the Company, no distributions shall be made (i) to the holders of shares of junior stock unless the

18

holders of Series A Preferred Stock shall have received, subject to adjustment as hereinafter provided in paragraph B, the greater of either (a) $100.00 per share plus an amount equal to accrued and unpaid dividends and distributions thereon, whether or not declared, to the date of such payment, or (b) an amount per share equal to 100 times the aggregate per share amount to be distributed to holders of shares of Common Stock or (ii) to the holders of shares of parity stock, unless simultaneously therewith distributions are made ratably on shares of Series A Preferred Stock and all other shares of such parity stock in proportion to the total amounts to which the holders of shares of Series A Preferred Stock are entitled under clause (i)(a) of this sentence and to which the holders of shares of such parity stock are entitled, in each case, upon such liquidation, dissolution or winding up.

(B)In the event the Company shall at any time after the Rights Declaration Date (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case, the aggregate amount to which holders of Series A Preferred Stock were entitled immediately prior to such event pursuant to clause (i)(b) of paragraph A of this Section 6 shall be adjusted by multiplying such amount by a fraction, the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event, and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event.

SECTION 7.CONSOLIDATION, MERGER, ETC. In case the Company shall enter into any consolidation, merger, combination or other transactions in which the shares of Common Stock are exchanged for or converted into other stock or securities, cash and/or any other property, then in any such case, each share of Series A Preferred Stock shall at the same time be similarly exchanged for or converted into an amount per share (subject to the provision for adjustment hereinafter set forth) equal to 100 times the aggregate amount of stock, securities, cash and/or any other property (payable in kind), as the case may be, into which or for which each share of Common Stock is converted or exchanged. In the event the Company shall at any time after the Rights Declaration Date (i) declare any dividend on outstanding shares of Common Stock payable in shares of Common Stock, (ii) subdivide outstanding shares of Common Stock, or (iii) combine outstanding shares of Common Stock into a smaller number of shares, then in each such case, the amount set forth in the immediately preceding sentence with respect to the exchange or conversion of shares of Series A Preferred Stock shall be adjusted by multiplying such amount by a fraction, the numerator of which shall be the number of shares of Common Stock that are outstanding immediately after such event, and the denominator of which shall be the number of shares of Common Stock that were outstanding immediately prior to such event.

SECTION 8.REDEMPTION. The shares of Series A Preferred Stock shall not be redeemable.

SECTION 9.RANKING. The shares of Series A Preferred Stock shall rank junior to all other series of the Preferred Stock and to any other class of preferred stock that hereafter may be issued by the Company as to the payment of dividends and the distribution of assets, unless the terms of any such series or class shall provide otherwise.

19

SECTION 10.AMENDMENT. The provisions of this Certificate of Designation shall not hereafter be amended, either directly or indirectly, or through merger or consolidation with another corporation, in any manner that would alter or change the powers, preferences or special rights of the Series A Preferred Stock so as to affect them adversely without the affirmative vote of the holders of at least a majority of the outstanding shares of Series A Preferred Stock, voting separately as a class.

SECTION 11.FRACTIONAL SHARES. The Series A Preferred Stock may be issued in fractions of a share, which fractions shall entitle the holder, in proportion to such holder's fractional shares, to exercise voting rights, receive dividends, participate in distributions, and to have the benefit of all other rights of holders of Series A Preferred Stock.

SECTION 12.CERTAIN DEFINITIONS. As used herein with respect to the Series A Preferred Stock, the following terms shall have the following meanings:

(1)The term "junior stock" (i) as used in Section 4, shall mean the Common Stock and any other class or series of capital stock of the Company hereafter authorized or issued over which the Series A Preferred Stock has preference or priority as to the payment of dividends, and (ii) as used in Section 6, shall mean the Common Stock and any other class or series of capital stock of the Company over which the Series A Preferred Stock has preference or priority in the distribution of assets on any liquidation, dissolution or winding up of the Company.

(2)The term "parity stock" (i) as used in Section 4, shall mean any class or series of stock of the Company hereafter authorized or issued ranking pari passu with the Series A Preferred Stock as to dividends, and (ii) as used in Section 6, shall mean any class or series of stock of the Company ranking pari passu with the Series A Preferred Stock in the distribution of assets on any liquidation, dissolution or winding up.

[The remainder of this page intentionally left blank.]

20

The foregoing Restated Certificate of Incorporation was duly adopted in accordance with the provisions of Title 18, Section 1080 of the Oklahoma Statutes after being proposed by the Directors and adopted by the Shareholders of OGE Energy Corp. in the manner and by the vote prescribed in Title 18, Section 1077 of the Oklahoma Statutes, and restates, integrates and further amends the certificate of incorporation.

In Witness Whereof, OGE Energy Corp. has caused this Certificate to be signed by its Chairman of the Board and Chief Executive Officer and attested to by its Corporate Secretary, this 28 day of June, 2011.

OGE Energy Corp., an Oklahoma corporation

By:	/s/ Peter B. Delaney
Name:	Peter B. Delaney
Title:	Chairman of the Board and
	Chief Executive Officer

Attest:

By:	/s/ Patricia D. Horn
Name:	Patricia D. Horn
Title:	Corporate Secretary

ACKNOWLEDGEMENT

STATE OF OKLAHOMA	)
	)	ss:
COUNTY OF OKLAHOMA	)

The foregoing Restated Certificate of Incorporation was acknowledged before me the 28 day of June, 2011, by Peter D. Delaney, as Chairman of the Board and Chief Executive Officer of OGE Energy Corp., an Oklahoma corporation.

(SEAL)	/s/ Kelly D. Lang
	Notary Public
	My Commission Expires:     9/23/2013
	My Commission Number:     09008044

21

EX-31.01

Exhibit 31.01

CERTIFICATIONS

I, Peter B. Delaney, certify that:

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date:  August 4, 2011

/s/ Peter B. Delaney

Peter B. Delaney

Chairman of the Board and

Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, Sean Trauschke, certify that:

1. I have reviewed this quarterly report on Form 10-Q of OGE Energy Corp;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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

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

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

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

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

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

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

Date:  August 4, 2011

/s/ Sean Trauschke

Sean Trauschke

Vice President and Chief Financial Officer

EX-32.01

Exhibit 32.01

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of the Company on Form 10-Q for the period ended June 30, 2011, as filed with the SEC (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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

August 4, 2011

/s/	Peter B. Delaney
	Peter B. Delaney
	Chairman of the Board
	and Chief Executive Officer

/s/	Sean Trauschke
	Sean Trauschke
	Vice President
	and Chief Financial Officer

XML



Long-Term Debt (Details) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	May 18, 2011
Debt Instrument [Line Items]
Percent of Principal Amount Subject to Optional Tender	100.00%
Amount of Debt Approved to Be Issued			$ 1,000,000,000
Proceeds from long-term debt	246,300,000	246,200,000
Senior notes [Member] | Senior Notes due 2041 [Member]
Debt Instrument [Line Items]
SERIES	5.25%
DATE DUE	May 15, 2041
Proceeds from long-term debt	250,000,000
Redeemable during the next 12 months
Debt Instrument [Line Items]
AMOUNT	135,400,000
Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
SERIES, minimum	0.25%
SERIES, maximum	0.44%
AMOUNT	47,000,000
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
SERIES, minimum	0.23%
SERIES, maximum	0.44%
AMOUNT	32,400,000
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
SERIES, minimum	0.35%
SERIES, maximum	0.50%
AMOUNT	$ 56,000,000
Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
DATE DUE	Jan. 01, 2025
Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
DATE DUE	Jan. 01, 2025
Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
DATE DUE	Jun. 01, 2027

XML



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net income	$ 109.3	$ 77.9	$ 139.0	$ 103.1
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.5 million, $0.3 million, $0.9 million and $1.0 million, respectively	0.5	0.5	1.0	1.0
Amortization of prior service cost, net of tax of ($0.1) million, $0, $0 and $0, respectively	0	0.1	0.2	0.1
Postretirement plans:
Amortization of deferred net loss, net of tax of $0.1 million, $0.2 million, $0.6 million and $0.6 million, respectively	0.6	0.3	0.8	0.9
Amortization of deferred net transition obligation, net of tax of ($0.1) million, $0.1 million, $0 and $0.1 million, respectively	0	0.1	0.1	0.3
Amortization of prior service cost, net of tax of $0.3 million, $0, $5.6 million and $0, respectively	(0.3)	0	9.8	(0.2)
Deferred commodity contracts hedging gains (losses), net of tax of $2.9 million, $7.8 million, $4.1 million and $6.2 million, respectively	5.5	12.3	7.0	9.6
Deferred interest rate swaps hedging gains, net of tax of $0, $0, $0.1 million and $0, respectively	0.1	0	0.2	0.1
Other comprehensive income (loss), net of tax	6.4	13.3	19.1	11.8
Comprehensive income (loss)	115.7	91.2	158.1	114.9
Less: Comprehensive income attributable to noncontrolling interest for sale of equity investment	0	0	(1.7)	0
Less: Comprehensive income attributable to noncontrolling interests	7.5	0.6	13.5	1.6
Total comprehensive income (loss) attributable to OGE Energy	$ 108.2	$ 90.6	$ 146.3	$ 113.3

XML



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) PARENTHETICAL (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax	$ 0.5	$ 0.3	$ 0.9	$ 1.0
Amortization of prior service cost, net of tax	(0.1)	0	0	0
Postretirement plans:
Amortization of deferred net loss, net of tax	0.1	0.2	0.6	0.6
Amortization of deferred net transition obligation, net of tax	(0.1)	0.1	0	0.1
Amortization of prior service cost, net of tax	0.3	0	5.6	0
Deferred commodity contracts hedging gains (losses), net of tax	2.9	7.8	4.1	6.2
Deferred interest rate swaps hedging gains, net of tax	$ 0	$ 0	$ 0.1	$ 0

XML



Report of Business Segments (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Segment Reporting Information [Line Items]
Operating revenues	$ 978.1	$ 887.2	$ 1,818.6	$ 1,763.0
Cost of goods sold	550.1	506.5	1,083.3	1,076.6
Gross margin on revenues	428.0	380.7	735.3	686.4
Other operation and maintenance	146.6	135.0	284.9	258.6
Depreciation and amortization	74.7	71.2	148.7	141.5
Taxes other than income	24.5	23.0	51.6	48.0
OPERATING INCOME	182.2	151.5	250.1	238.3
Total assets	8,135.5	7,294.1	8,135.5	7,294.1	7,669.1
Electric Utility [Member]
Segment Reporting Information [Line Items]
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
Total assets	6,290.5	5,775.9	6,290.5	5,775.9
Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Operating revenues	108.0	97.1	208.2	208.2
Cost of goods sold	69.5	60.9	133.5	127.1
Gross margin on revenues	38.5	36.2	74.7	81.1
Other operation and maintenance	13.0	12.6	22.1	23.6
Depreciation and amortization	5.8	5.4	11.2	10.8
Taxes other than income	3.3	3.4	7.6	7.3
OPERATING INCOME	16.4	14.8	33.8	39.4
Total assets	2,297.3	1,585.2	2,297.3	1,585.2
Gathering and Processing [Member]
Segment Reporting Information [Line Items]
Operating revenues	289.1	235.4	555.8	483.3
Cost of goods sold	210.9	168.6	407.2	348.6
Gross margin on revenues	78.2	66.8	148.6	134.7
Other operation and maintenance	26.3	23.5	53.1	44.8
Depreciation and amortization	13.4	12.5	26.9	24.9
Taxes other than income	1.7	1.6	3.6	3.5
OPERATING INCOME	36.8	29.2	65.0	61.5
Total assets	1,106.7	907.9	1,106.7	907.9
Marketing [Member]
Segment Reporting Information [Line Items]
Operating revenues	168.3	189.0	366.4	434.7
Cost of goods sold	170.4	192.9	369.7	437.2
Gross margin on revenues	(2.1)	(3.9)	(3.3)	(2.5)
Other operation and maintenance	2.0	2.1	4.1	4.8
Depreciation and amortization	0.1	0	0.1	0
Taxes other than income	(0.1)	0	0.1	0.2
OPERATING INCOME	(4.1)	(6.0)	(7.6)	(7.5)
Total assets	80.2	104.5	80.2	104.5
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Cost of goods sold	0	0	0	0
Gross margin on revenues	0	0	0	0
Other operation and maintenance	(4.2)	(3.5)	(8.9)	(7.6)
Depreciation and amortization	3.3	2.7	6.6	5.5
Taxes other than income	0.8	0.8	2.4	2.1
OPERATING INCOME	0.1	0	(0.1)	0
Total assets	2,937.3	2,691.6	2,937.3	2,691.6
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(156.0)	(147.1)	(302.6)	(320.0)
Cost of goods sold	(155.0)	(146.7)	(300.8)	(317.9)
Gross margin on revenues	(1.0)	(0.4)	(1.8)	(2.1)
Other operation and maintenance	(0.7)	(0.9)	(1.5)	(2.1)
Depreciation and amortization	0	0	0	0
Taxes other than income	0	0	0	0
OPERATING INCOME	(0.3)	0.5	(0.3)	0
Total assets	$ (4,576.5)	$ (3,771.0)	$ (4,576.5)	$ (3,771.0)

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Rate Matters and Regulation

6 Months Ended

Jun. 30, 2011

Regulated Operations [Abstract]

Rate Matters and Regulation

Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 15 to the Company's Consolidated 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

OG&E Wholesale Agreement

On May 28, 2009, OG&E sent a termination notice to the Arkansas Valley Electric Cooperative that OG&E would terminate its wholesale power agreement to all points of delivery where OG&E sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011.  In December 2010, OG&E and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby OG&E will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015.  On January 3, 2011, OG&E 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 OG&E'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.

OG&E Long-Term Gas Supply Agreements    

In May 2010, the OCC approved OG&E's request for a waiver of the competitive bid rules to allow OG&E to negotiate desired long-term gas purchase agreements. On June 29, 2010, OG&E 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 OG&E and account for 25 percent of its currently projected natural gas fuel supply needs over the same time period. On September 26, 2010, OG&E filed a motion with the OCC to dismiss this case. On July 5, 2011, OG&E received an order from the OCC dismissing the case without prejudice.

OG&E Crossroads Wind Project

As previously disclosed, on July 29, 2010, OG&E received an order from the OCC authorizing OG&E 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, OG&E entered into an interconnection agreement with the SPP for Crossroads which will allow Crossroads to interconnect at the anticipated 227.5 megawatts. 

OG&E 2010 Arkansas Rate Case Filing

On September 28, 2010, OG&E 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. OG&E 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-OG&E transmission owners throughout the SPP that have been allocated to OG&E 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 OG&E 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 OG&E 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 OG&E'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.

OG&E SPP Cost Tracker

On October 7, 2010, OG&E 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-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission ratesand (ii) SPP administrative fees. OG&E 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.  OG&E also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give OG&E 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 OG&E to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. OG&E 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 OG&E 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 OG&E's 2011 Oklahoma general rate case filing, OG&E 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 OG&E by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.

OG&E FERC Transmission Rate Incentive Filing

On February 18, 2011, OG&E 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.  OG&E requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five345 kilovolt Extra High Voltage transmission projects to be constructed and owned by OG&E within the SPP's region.  OG&E 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 OG&E'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 15 of the Company's 2010 Form 10-K.

OG&E 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 OG&E customers, on March 15, 2011, OG&E filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting.  In seeking approval of these programs, OG&E 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 OG&E's energy efficiency plan for 2011 and approving OG&E's energy efficiency cost recovery rider for 2011. In Arkansas, OG&E'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 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 OG&E) 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 OG&E) 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 OG&E 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 OG&E. Nevertheless, at the present time, the Company has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.

OG&E Smart Grid Project

As previously reported in the Company's 2010 Form 10-K, on December 17, 2010, OG&E 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, OG&E reached a settlement agreement with all the parties to the APSC consideration of OG&E'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. OG&E 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 OG&E 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) OG&E 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 OG&E'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 OG&E's next general rate case. OG&E 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 OG&E'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 OG&E's application of the 2009 fuel adjustment clause.  On December 28, 2010, OG&E responded by filing the necessary information and documents to satisfy the OCC's minimum filing requirement rules. An intervenor representing a group of OG&E's industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by OG&E to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing natural gas supply agreement between OG&E and Enogex.  OG&E 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.

OG&E Pension Tracker Modification Filing

On February 22, 2011, OG&E filed an application with the OCC requesting that OG&E's pension tracker be modified to include the difference between the level of retiree medical costs authorized in OG&E'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 OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. A hearing in this matter was held on July 14, 2011. OG&E expects to receive a decision from the OCC during the third quarter of 2011.

OG&E 2011 Oklahoma Rate Case Filing

As part of the Joint Stipulation and Settlement Agreement reached in OG&E's 2009 Oklahoma rate case filing, the parties agreed that OG&E would file a rate case on or before June 30, 2011. On May 27, 2011, OG&E requested an extension until the end of July 2011 for filing the Oklahoma rate case. On July 28, 2011, OG&E filed its application with the OCC requesting an annual rate increase of $73.3 million, or a 4.3 percent increase in its rates. OG&E 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, OG&E 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. OG&E expects to receive an order from the OCC in early 2012.

Enogex FERC Section 311 2007 Rate Case

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for Section 311 service in the East Zone and West Zone. Enogex's filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008.  A number of parties intervened and some also filed protests. Enogex did not place the increased rates set forth in its October 2007 rate filing into effect but rather continued to provide interruptible Section 311 service under the maximum Section 311 rates for both zones approved by the FERC in the previous rate case. A final settlement was filed with the FERC on August 5, 2010 and an order is pending. With the filing of Enogex's 2009 rate case discussed below, the rate period for the 2007 rate case became a limited locked-in period from January 2008 through May 2009.

On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex 2007 rate case with a separate Enogex application pending before the FERC allowing Enogex to lease firm capacity to MEP and with separate applications filed by MEP with the FERC for a certificate to construct and operate the MEP pipeline and to lease firm capacity from Enogex. Enogex and MEP separately opposed this intervenor's protests and assertions in its initial and subsequent pleadings. On July 25, 2008, the FERC issued an order (i) approving the MEP project including the approval of a limited jurisdiction certificate and (ii) authorizing the Enogex lease agreement with MEP. Accordingly, Enogex proceeded with the construction of facilities necessary to implement this service. On August 25, 2008, a protestor sought rehearing which the FERC denied. Enogex commenced service to MEP under the lease agreement on June 1, 2009. On July 16, 2009, the protestor filed, with the United States Court of Appeals for the District of Columbia Circuit, a petition for review of the FERC's orders approving the MEP construction and the MEP lease of capacity from Enogex requesting that such orders be modified or set aside on the grounds that they are arbitrary, capricious and contrary to law.  On December 28, 2010, the Court of Appeals issued an opinion generally upholding the FERC's orders, but remanding the case for further explanation of one aspect of the FERC's reasoning.  The Court of Appeals emphasized that it was not vacating the FERC's orders and that its approval of the Enogex lease agreement with MEP remains in effect and legally binding.  On remand, the FERC must clarify that its decision was based on a finding that the lease does not adversely affect existing customers on Enogex's system.  Enogex anticipates that the FERC will issue an order on remand in the first half of 2011.  On January 21, 2011, Apache Corporation filed a motion asking the FERC to establish procedures on remand and to either condition the lease on Enogex's willingness to provide firm Section 311 transportation service to existing customers on all portions of its system or to establish an expedited briefing schedule.  On February 7, 2011, Enogex, MEP and Chesapeake Energy Corporation filed a joint answer asking the FERC to find, among other things, that the reduction in the amount of interruptible transportation capacity available due to the MEP lease did not have an adverse affect on Apache Corporation and to acknowledge that Apache Corporation's request to condition the lease on the provision of West Zone 311 firm transportation service has been addressed as Enogex filed a rate case on January 28, 2011 proposing to implement such service effective March 1, 2011. On March 1, 2011, Apache Corporation filed an answer seeking to refute some of the arguments presented in the joint answer filed by Enogex, MEP and Chesapeake Energy Corporation.  On March 3, 2011, the FERC issued an order on remand affirming the authorizations previously granted to Enogex and MEP and clarifying the legal standard applied in response to the court's directive.  On April 4, 2011, Apache Corporation filed a request for rehearing of the FERC's order on remand. The FERC issued a tolling order on May 4, 2011 indefinitely extending the time for the FERC to act on Apache Corporation's motion for rehearing. Once the FERC acts on Apache Corporation's request for rehearing, the order on remand and the order on rehearing become subject to appeal before the United States Court of Appeals for the District of Columbia Circuit.

Enogex FERC Section 311 2009 Rate Case

On March 27, 2009, Enogex filed a petition for rate approval with the FERC to set the maximum rates for its new firm East Zone Section 311 transportation service and to revise the rates for its existing East and West Zone interruptible Section 311 transportation service. In anticipation of offering this new service, Enogex had filed with the FERC, as required by the FERC's regulations, a revised Statement of Operating Conditions Applicable to Transportation Services to describe the terms, conditions and operating arrangements for the new service.  Enogex made the Statement of Operating Conditions filing on February 27, 2009.  Enogex began offering firm East Zone Section 311 transportation service on April 1, 2009. The revised East and West Zone zonal rates for the Section 311 interruptible transportation service became effective June 1, 2009. The rates for the firm East Zone Section 311 transportation service and the increase in the rates for East and West Zone and interruptible Section 311 service are being collected, subject to refund, pending the FERC approval of the proposed rates. A number of parties intervened in both the rate case and the Statement of Operating Conditions filing and some additionally filed protests. On January 4, 2010, the FERC Staff submitted an offer proposing various adjustments to Enogex's filed cost of service. On April 27, 2010, Enogex submitted comments to the FERC Staff stating that it would agree to the offer, contingent upon all parties agreeing to support or not oppose.  Parties have until September 15, 2011 to submit comments stating whether they support, or do not oppose, the FERC Staff's offer. 

Enogex FERC Section 311 2011 RateCase

On January 28, 2011, Enogex submitted a new rate filing to the FERC to set the maximum rate for a new firm Section 311 transportation service in the West Zone of its system and to revise the currently effective maximum rates for Section 311 interruptible transportation service in the East Zone and West Zone.  Along with establishing the rate for a new firm service in the West Zone, Enogex's filing requested a decrease in the maximum interruptible zonal rates in the West Zone and to retain the currently effective rates for firm and interruptible services in the East Zone.  Enogex reserved the right to implement the higher rates for firm and interruptible services in the East Zone supported by the cost of service to the extent an expeditious settlement agreement cannot be reached in the proceeding.  Enogex proposed that the rates be placed into effect on March 1, 2011.  At Enogex's request, the protest deadline was extended to September 15, 2011.  The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action.

Enogex 2011 Fuel Filing

On February 28, 2011, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2011 through March 31, 2012).  Along with the revised fuel percentages, Enogex also requested authority to revise its Statement of Operating Conditions to permanently change the annual filing date to February 28.  The deadline for interventions and protests on Enogex's filing was March 15, 2011, and no protests were filed.  A FERC order is pending.

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DOCUMENT AND ENTITY INFORMATION	6 Months Ended
	Jun. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	0001021635
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	97,973,168
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011

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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) (USD $) In Millions, except Share data	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011
Equity [Abstract]
Stock Issued During Period, Shares, Dividend Reinvestment Plan and Stock Purchase Plan	64,849	145,846
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan	$ 3.4	$ 7.2
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan	2,500,442	2,500,442

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ArcLight Transaction (Tables)

6 Months Ended

Jun. 30, 2011

Noncontrolling Interest [Abstract]

Schedule of Equity Attributable to Changes in Ownership Percentage [Table Text Block]

The following table summarizes changes in OGE Energy's equity attributable to changes in its ownership interest in Enogex Holdings during the six months ended June 30, 2011. There were no contributions by OGE Energy or the ArcLight group to fund Enogex LLC's 2011 capital requirements during the three months ended June 30, 2011. Also, there were no sales of additional membership interests in Enogex Holdings to the ArcLight group during the three months ended June 30, 2011.

(In millions)
Net income attributable to OGE Energy	$	127.8
Transfers (to) from the noncontrolling interest
Increase in paid-in capital for sale of 100,000 units of Enogex Holdings	0.9
Increase in paid-in capital for issuance of 4,303,007 units of Enogex Holdings	28.2
Decrease in paid-in capital for deferred income taxes attributable to the sale and issuance of units
of Enogex Holdings	(11.2		)
Net transfers from the noncontrolling interest	17.9
Change from net income attributable to OGE Energy and transfers from noncontrolling interest	$	145.7

Schedule of Change in Ownership Percentage [Table Text Block]

The following table summarizes changes in OGE Holdings' and the ArcLight group's membership interest in Enogex Holdings for the six months ended June 30, 2011. Prior to November 1, 2010, Enogex Holdings was wholly owned by OGE Energy.

(In millions)	OGE Holdings		ArcLight group		Total
Balance at December 31, 2010 (units)	90.1		9.9		100.0
Ownership percentage at December 31, 2010	90.1	%	9.9	%	100.0	%
Sale of 100,000 units of Enogex Holdings (A)	(0.1	)	0.1		—
Issuance of 4,303,007 units of Enogex Holdings (B)	0.4		3.9		4.3
Balance at June 30, 2011 (units)	90.4		13.9		104.3
Ownership percentage at June 30, 2011	86.7	%	13.3	%	100.0	%

(A) On February 1, 2011, OGE Energy sold a 0.1 percent membership interest in Enogex Holdings to the ArcLight group for $1.9 million.

(B) In February 2011, OGE Energy and the ArcLight group made contributions of $8.0 million and $71.6 million, respectively, to fund a portion of Enogex LLC's 2011 capital requirements.

Schedule of Distributions Made to Partners [Table Text Block]

The below table summarizes these distributions during the six months ended June 30, 2011.

	OGE Holdings		ArcLight group's
(In millions)	Portion		Portion		Total Distribution
First quarter 2011	$	7.5	$	0.8	$	8.3
Second quarter 2011	34.3		5.3		39.6
Total	$	41.8	$	6.1	$	47.9

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Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Accumulated other comprehensive loss, net of tax	$ (41.8)	$ (60.2)
Noncontrolling Interest
Accumulated other comprehensive loss, net of tax	(5.1)	(5.8)
Atoka Noncontrolling Interest [Member]
Accumulated other comprehensive loss, net of tax	0	0
Parent [Member]
Accumulated other comprehensive loss, net of tax	(46.9)	(66.0)
Pension Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(30.1)	(31.1)
Pension Plans, Defined Benefit [Member] | Defined Benefit Plan Prior Service Cost [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(0.3)	(0.5)
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(12.8)	(13.6)
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plan Prior Service Cost [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	9.8	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plan Net Transition Obligation [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(0.2)	(0.3)
Commodity Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(12.5)	(19.5)
Interest Rate Swap [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	$ (0.8)	$ (1.0)

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 and examples of each 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. Instruments classified as Level 1 include natural gas futures, swaps and option transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

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 over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing.

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).  Instruments classified as Level 3 include NGLs options.

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.  The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining.  Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.  Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, NGLs options contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management's best estimate of fair value.  These contracts are classified as Level 3.

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.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset.  The reporting entity's choice to offset or not must be applied consistently.  A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets.  The Company has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at June 30, 2011 and December 31, 2010 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010.

June 30, 2011
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	12.3		$	12.7		$	—	$	—
Significant other observable inputs (Level 2)	1.7			15.4			6.1		5.2
Significant unobservable inputs (Level 3)	2.5			—			—		—
Total fair value	16.5			28.1			6.1		5.2
Netting adjustments	(15.4		)	(15.8		)	—		—
Total	$	1.1		$	12.3		$	6.1	$	5.2
December 31, 2010
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	20.6		$	20.2		$	—	$	—
Significant other observable inputs (Level 2)	2.7			30.7			2.5		2.8
Significant unobservable inputs (Level 3)	13.3			—			—		—
Total fair value	36.6			50.9			2.5		2.8
Netting adjustments	(34.4		)	(34.1		)	—		—
Total	$	2.2		$	16.8		$	2.5	$	2.8

(A) The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $2.5 million and $3.9 million at June 30, 2011 and December 31, 2010, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

	Commodity Contracts
	Assets						Liabilities
(In millions)	2011			2010			2011		2010
Balance at January 1	$	13.3		$	49.0		$	—	$	14.7
Total gains or losses
Included in other comprehensive income	(4.8		)	(3.9		)	—		(5.1		)
Settlements	(3.3		)	(4.1		)	—		(1.4		)
Balance at March 31	$	5.2		$	41.0		$	—	$	8.2
Total gains or losses
Included in other comprehensive income	(1.0		)	7.2			—		(3.7		)
Settlements	(1.7		)	(6.1		)	—		(2.7		)
Balance at June 30	$	2.5		$	42.1		$	—	$	1.8

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 Assets
Energy Derivative Contracts	$	1.1	$	1.1	$	2.2	$	2.2
Price Risk Management Liabilities
Energy Derivative Contracts	$	12.3	$	12.3	$	16.8	$	16.8
Long-Term Debt
OG&E Senior Notes	$	1,903.7	$	2,115.4	$	1,655.0	$	1,831.5
OGE Energy Senior Notes	99.7		109.0		99.7		106.4
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Enogex LLC Senior Notes	448.0		494.2		447.8		480.7
Enogex LLC Revolving Credit Agreement	—		—		25.0		25.0

The carrying value of the financial instruments on the Condensed Consolidated 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.  However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values.  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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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis [Table Text Block]

The following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at June 30, 2011 and December 31, 2010 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010.

June 30, 2011
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	12.3		$	12.7		$	—	$	—
Significant other observable inputs (Level 2)	1.7			15.4			6.1		5.2
Significant unobservable inputs (Level 3)	2.5			—			—		—
Total fair value	16.5			28.1			6.1		5.2
Netting adjustments	(15.4		)	(15.8		)	—		—
Total	$	1.1		$	12.3		$	6.1	$	5.2
December 31, 2010
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	20.6		$	20.2		$	—	$	—
Significant other observable inputs (Level 2)	2.7			30.7			2.5		2.8
Significant unobservable inputs (Level 3)	13.3			—			—		—
Total fair value	36.6			50.9			2.5		2.8
Netting adjustments	(34.4		)	(34.1		)	—		—
Total	$	2.2		$	16.8		$	2.5	$	2.8

(A) The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $2.5 million and $3.9 million at June 30, 2011 and December 31, 2010, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation [Table Text Block]

The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

	Commodity Contracts
	Assets						Liabilities
(In millions)	2011			2010			2011		2010
Balance at January 1	$	13.3		$	49.0		$	—	$	14.7
Total gains or losses
Included in other comprehensive income	(4.8		)	(3.9		)	—		(5.1		)
Settlements	(3.3		)	(4.1		)	—		(1.4		)
Balance at March 31	$	5.2		$	41.0		$	—	$	8.2
Total gains or losses
Included in other comprehensive income	(1.0		)	7.2			—		(3.7		)
Settlements	(1.7		)	(6.1		)	—		(2.7		)
Balance at June 30	$	2.5		$	42.1		$	—	$	1.8

Schedule of Fair Value and Carrying Amount of PRM Financial Instruments [Table Text Block]

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 Assets
Energy Derivative Contracts	$	1.1	$	1.1	$	2.2	$	2.2
Price Risk Management Liabilities
Energy Derivative Contracts	$	12.3	$	12.3	$	16.8	$	16.8
Long-Term Debt
OG&E Senior Notes	$	1,903.7	$	2,115.4	$	1,655.0	$	1,831.5
OGE Energy Senior Notes	99.7		109.0		99.7		106.4
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Enogex LLC Senior Notes	448.0		494.2		447.8		480.7
Enogex LLC Revolving Credit Agreement	—		—		25.0		25.0

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Derivative Instruments and Hedging Activities, Quantitative Disclosures Related to Derivative Instruments (Details) (Enogex [Member])	Jun. 30, 2011		Dec. 31, 2010
Derivative [Line Items]
Derivative, Number of Fair Value Hedges Held	0		0
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NGL [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	700,000	[1]
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Natural gas [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	1,600,000	[1]
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | Natural gas [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	2,600,000	[1]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Physical [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	48,500,000	[2],[3],[4],[5]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Physical [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	15,400,000	[2],[3],[4],[5]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	54,300,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	55,500,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Options [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	10,500,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Options [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	9,100,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Basis Swaps [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	8,400,000	[2],[4]
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Basis Swaps [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (Barrels or MMBtu)	9,100,000	[2],[4]
Natural gas [Member]
Derivative [Line Items]
Percent of Contract with Durations of One Year or Less	90.00%
Percent of Contracts With Durations of More Than One Year and Less Than Two Years	6.80%
Percent of Contracts Having a Duration of More Than Two Years	3.20%

[1] Natural gas in Million British thermal unit; NGLs in barrels.

[2] 90.0 percent of the natural gas contracts have durations of one year or less, 6.8 percent have durations of more than one year and less than two years and 3.2 percent have durations of more than two years.

[3] Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

[4] Natural gas in Million British thermal unit.

[5] Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

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ArcLight Transaction (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2010	Jun. 30, 2011		Jun. 30, 2010
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Period Start, Total Ownership Percentage		100.00%		100.00%
Ending Period, Total Ownership Percentage	100.00%			100.00%
Percentage of Subsidiary Sold to Noncontrolling Interest				0.10%
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates				$ 1.9
Net Income Attributable to OGE Energy	103.0		77.3	127.8		101.5
Increase in paid-in capital for sale of 100,000 units of Enogex Holdings	0	0.9
Increase in paid-in capital for issuance of 4,303,007 units of Enogex Holdings	28.2
Deferred Income Taxes Attributable To Contributions From Noncontrolling Interest Partners				(11.2)
Net transfers from the noncontrolling interest	17.9
Change from net income attributable to OGE Energy and transfers from noncontrolling interest	145.7
OGE Holdings [Member]
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Beginning period, balance		90,100,000		90,100,000
Ownership percentage, OGE Holdings, at beginning of period		90.10%		90.10%
Sale of 100,000 units of Enogex Holdings				(100,000)	[1]
Issuance of 4,303,007 units of Enogex Holdings				400,000	[2]
Ending period, balance	90,400,000			90,400,000
Ownership percentage, OGE Holdings, at end of period	86.70%			86.70%
Contributions Towards Meeting Capital Requirements	0	8.0
Noncontrolling Interest
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Deferred Income Taxes Attributable To Contributions From Noncontrolling Interest Partners				0
ArcLight Group [Member]
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Beginning period, balance		9,900,000		9,900,000
Ownership percentage, ArcLight Group, at beginning of period		9.90%		9.90%
Sale of 100,000 units of Enogex Holdings				100,000	[1]
Issuance of 4,303,007 units of Enogex Holdings				3,900,000	[2]
Ending period, balance	13,900,000			13,900,000
Ownership Percentage, ArcLight Group, at end of period	13.30%			13.30%
Contributions Towards Meeting Capital Requirements	$ 0	$ 71.6
Enogex Holdings [Member]
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
Beginning period, balance		100,000,000		100,000,000
Sale of 100,000 units of Enogex Holdings				0	[1]
Issuance of 4,303,007 units of Enogex Holdings				4,300,000	[2]
Ending period, balance	104,300,000			104,300,000
Limited Liability Corp Units Sold				100,000
Limited Liability Corp Units Issued				4,303,007

[1] On February 1, 2011, OGE Energy sold a 0.1 percent membership interest in Enogex Holdings to the ArcLight group for $1.9 million.

[2] In February 2011, OGE Energy and the ArcLight group made contributions of $8.0 million and $71.6 million, respectively, to fund a portion of Enogex LLC's 2011 capital requirements.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

The following table is a summary of OG&E'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 Consolidated Balance Sheets.

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

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Common Equity

6 Months Ended

Jun. 30, 2011

Equity [Abstract]

Common Equity

Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 64,849 shares and 145,846 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months ended June 30, 2011 and received proceeds of $3.4 million and $7.2 million, respectively, during the three and six months ended June 30, 2011.  The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital requirements or working capital needs.  At June 30, 2011, there were 2,500,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings Per Share

Basic earnings per share is calculated by dividing net income attributable to OGE Energy by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units. Basic and diluted earnings per share for the Company were calculated as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2011		2010		2011		2010
Net Income Attributable to OGE Energy	$	103.0	$	77.3	$	127.8	$	101.5
Average Common Shares Outstanding
Basic average common shares outstanding	98.0		97.3		97.8		97.2
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.3		1.4		1.4		1.4
Diluted average common shares outstanding	99.3		98.7		99.2		98.6
Basic Earnings Per Average Common Share
Attributable to OGE Energy Common Shareholders	$	1.05	$	0.79	$	1.31	$	1.04
Diluted Earnings Per Average Common Share
Attributable to OGE Energy Common Shareholders	$	1.04	$	0.78	$	1.29	$	1.03
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Unaudited) (USD $) In Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Balance at Dec. 31, 2009	$ 2,060.8	$ 1.0	$ 886.7	$ 1,227.8	$ (74.7)	$ 20.0
Comprehensive income (loss)
Net income	103.1	0	0	101.5	0	1.6
Other comprehensive income (loss), net of tax	11.8	0	0	0	11.8	0
Comprehensive income (loss)	114.9	0	0	101.5	11.8	1.6
Dividends declared on common stock	(70.6)	0	0	(70.6)	0	0
Issuance of common stock	9.8	0	9.8	0	0	0
Stock-based compensation	4.8	0	4.8	0	0	0
Contributions from noncontrolling interest partners	0
Distributions to noncontrolling interest partners	0
Balance at Jun. 30, 2010	2,119.7	1.0	901.3	1,258.7	(62.9)	21.6
Balance at Dec. 31, 2010	2,400.0	1.0	968.2	1,380.6	(60.2)	110.4
Comprehensive income (loss)
Net income	139.0	0	0	127.8	0	11.2
Other comprehensive income (loss), net of tax	19.1	0	0	0	18.4	0.7
Comprehensive income (loss)	158.1	0	0	127.8	18.4	11.9
Dividends declared on common stock	(73.5)	0	0	(73.5)	0	0
Issuance of common stock	7.5	0	7.5	0	0	0
Stock-based compensation	0.1	0	0.1	0	0	0
Contributions from noncontrolling interest partners	73.5	0	29.1	0	0	44.4
Distributions to noncontrolling interest partners	(6.1)	0	0	0	0	(6.1)
Deferred income taxes attributable to contributions from noncontrolling interest partners	(11.2)	0	(11.2)	0	0	0
Balance at Jun. 30, 2011	$ 2,548.4	$ 1.0	$ 993.7	$ 1,434.9	$ (41.8)	$ 160.6

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Report of Business Segments (Tables)

6 Months Ended

Jun. 30, 2011

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following tables summarize the results of the Company's business segments for the three and six months ended June 30, 2011 and 2010.

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
June 30, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	568.7	$	108.0	$	289.1	$	168.3		$	—		$	(156.0	)	$	978.1
Cost of goods sold	254.3		69.5		210.9		170.4			—			(155.0		)	550.1
Gross margin on revenues	314.4		38.5		78.2		(2.1		)	—			(1.0		)	428.0
Other operation and maintenance	110.2		13.0		26.3		2.0			(4.2		)	(0.7		)	146.6
Depreciation and amortization	52.1		5.8		13.4		0.1			3.3			—			74.7
Taxes other than income	18.8		3.3		1.7		(0.1		)	0.8			—			24.5
Operating income (loss)	$	133.3	$	16.4	$	36.8	$	(4.1	)	$	0.1		$	(0.3	)	$	182.2
Total assets	$	6,290.5	$	2,297.3	$	1,106.7	$	80.2		$	2,937.3		$	(4,576.5	)	$	8,135.5

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
June 30, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	512.8	$	97.1	$	235.4	$	189.0		$	—		$	(147.1	)	$	887.2
Cost of goods sold	230.8		60.9		168.6		192.9			—			(146.7		)	506.5
Gross margin on revenues	282.0		36.2		66.8		(3.9		)	—			(0.4		)	380.7
Other operation and maintenance	101.2		12.6		23.5		2.1			(3.5		)	(0.9		)	135.0
Depreciation and amortization	50.6		5.4		12.5		—			2.7			—			71.2
Taxes other than income	17.2		3.4		1.6		—			0.8			—			23.0
Operating income (loss)	$	113.0	$	14.8	$	29.2	$	(6.0	)	$	—		$	0.5		$	151.5
Total assets	$	5,775.9	$	1,585.2	$	907.9	$	104.5		$	2,691.6		$	(3,771.0	)	$	7,294.1

			Transportation		Gathering
Six Months Ended	Electric		and		and					Other
June 30, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	990.8	$	208.2	$	555.8	$	366.4		$	—		$	(302.6	)	$	1,818.6
Cost of goods sold	473.7		133.5		407.2		369.7			—			(300.8		)	1,083.3
Gross margin on revenues	517.1		74.7		148.6		(3.3		)	—			(1.8		)	735.3
Other operation and maintenance	216.0		22.1		53.1		4.1			(8.9		)	(1.5		)	284.9
Depreciation and amortization	103.9		11.2		26.9		0.1			6.6			—			148.7
Taxes other than income	37.9		7.6		3.6		0.1			2.4			—			51.6
Operating income (loss)	$	159.3	$	33.8	$	65.0	$	(7.6	)	$	(0.1	)	$	(0.3	)	$	250.1
Total assets	$	6,290.5	$	2,297.3	$	1,106.7	$	80.2		$	2,937.3		$	(4,576.5	)	$	8,135.5

			Transportation		Gathering
Six Months Ended	Electric		and		and					Other
June 30, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	956.8	$	208.2	$	483.3	$	434.7		$	—		$	(320.0	)	$	1,763.0
Cost of goods sold	481.6		127.1		348.6		437.2			—			(317.9		)	1,076.6
Gross margin on revenues	475.2		81.1		134.7		(2.5		)	—			(2.1		)	686.4
Other operation and maintenance	195.1		23.6		44.8		4.8			(7.6		)	(2.1		)	258.6
Depreciation and amortization	100.3		10.8		24.9		—			5.5			—			141.5
Taxes other than income	34.9		7.3		3.5		0.2			2.1			—			48.0
Operating income (loss)	$	144.9	$	39.4	$	61.5	$	(7.5	)	$	—		$	—		$	238.3
Total assets	$	5,775.9	$	1,585.2	$	907.9	$	104.5		$	2,691.6		$	(3,771.0	)	$	7,294.1

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

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 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	$	1.9	$	1.5	$	3.7	$	3.1
Earnings per share	0.8		0.4		3.0		0.8
Total performance units	2.7		1.9		6.7		3.9
Restricted stock	0.2		0.3		0.5		0.4
Total compensation expense	$	2.9	$	2.2	$	7.2	$	4.3
Income tax benefit	$	1.1	$	0.9	$	2.8	$	1.6

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

	Shares	Fair Value
Grants
Restricted stock	829	$50.61

The Company 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 the Company's stock incentive plans related to exercised stock options, restricted stock grants and payouts of earned performance units. 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. The Company received $0.1 million and $0.8 million, respectively, during the three and six months ended June 30, 2011 related to exercised stock options and realized an income tax benefit for the tax deductions from the exercised stock options of less than $0.1 million and $0.2 million, respectively, during the three and six months ended June 30, 2011.

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Short-Term Debt and Credit Facilities

6 Months Ended

Jun. 30, 2011

Short-term Debt [Abstract]

Short-Term Debt and Credit Facilities

Short-Term Debt and Credit Facilities

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.  The short-term debt balance was $211.1 million and $145.0 million at June 30, 2011 and December 31, 2010, respectively.  The following table provides information regarding the Company's revolving credit agreements and available cash at June 30, 2011.

Revolving Credit Agreements and Available Cash
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	596.0	$	211.1	0.34	%	(D)	December 6, 2012
OG&E (C)	389.0		2.2		0.14	%	(D)	December 6, 2012
Enogex LLC (E)	250.0		—		—	%	(D)	March 31, 2013
	1,235.0		213.3		0.34	%
Cash	5.1		N/A		N/A			N/A
Total	$	1,240.1	$	213.3	0.34	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2011.

(B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  At June 30, 2011, there was $211.1 million in outstanding commercial paper borrowings.

(C) This bank facility is available to back up OG&E'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.

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

(E) This bank facility is available to provide revolving credit borrowings for Enogex LLC.  As Enogex LLC's credit agreement matures on March 31, 2013, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Condensed Consolidated Balance Sheets.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions.  Pricing grids associated with the 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 the Company's short-term borrowings, but a reduction in 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.

OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis.  OG&E 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.

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Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2011

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

The following table summarizes the components of accumulated other comprehensive loss at June 30, 2011 and December 31, 2010 attributable to OGE Energy.  At both June 30, 2011 and December 31, 2010, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka.

	June 30,			December 31,
(In millions)	2011			2010
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	(30.1	)	$	(31.1	)
Prior service cost	(0.3		)	(0.5		)
Postretirement plans:
Net loss	(12.8		)	(13.6		)
Prior service cost	9.8			—
Net transition obligation	(0.2		)	(0.3		)
Deferred commodity contracts hedging losses	(12.5		)	(19.5		)
Deferred interest rate swaps hedging losses	(0.8		)	(1.0		)
Total accumulated other comprehensive loss	(46.9		)	(66.0		)
Less:  Accumulated other comprehensive loss attributable to noncontrolling interests	(5.1		)	(5.8		)
Accumulated other comprehensive loss, net of tax	$	(41.8	)	$	(60.2	)

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2011

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

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

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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 primarily uses forward physical contracts, commodity price swap contracts and commodity price option features to manage the Company's commodity price risk exposures. Commodity derivative instruments used by the Company are as follows:

• NGLs put options and NGLs swaps are used to manage Enogex's NGLs exposure associated with its processing agreements;

• natural gas swaps are used to manage Enogex's keep-whole natural gas exposure associated with its processing operations and Enogex's natural gas exposure associated with operating its gathering, transportation and storage assets;

• natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OER's natural gas exposure associated with its storage and transportation contracts; and

• natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OER's marketing and trading activities.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated 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) commodity contracts for the purchase and sale of natural gas used in or produced by its operations, (ii) commodity contracts for the sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.  Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

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. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument.  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.

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing, pipeline and storage operations (operational gas hedges).  The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex's cash flow hedges at June 30, 2011 mature during the remainder of 2011.

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

Derivative instruments not designated as hedging instruments are utilized in OER's asset management, marketing and trading activities.  For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

At June 30, 2011, the Company had the following derivative instruments that were designated as cash flow hedges.

	2011 Gross Notional
(In millions)	Volume (A)
Enogex processing hedges
NGLs sales	0.7
Natural gas purchases	2.6
Enogex marketing hedges
Natural gas sales	1.6

(A) Natural gas in Million British thermal unit; NGLs in barrels.

At June 30, 2011, the Company had the following derivative instruments that were not designated as hedging instruments.

(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	15.4	48.5
Fixed Swaps/Futures	55.5	54.3
Options	9.1	10.5
Basis Swaps	9.1	8.4

(A) Natural gas in Million British thermal unit.  

(B) 90.0 percent of the natural gas contracts have durations of one year or less, 6.8 percent have durations of more than one year and less than two years and 3.2 percent have durations of more than two years.

(C) Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

(D) Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at June 30, 2011 are as follows:

		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	2.5	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		14.4
Financial Futures/Swaps	Other Current Assets	0.5		—
Total		$	3.0	$	14.4
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.2	$	0.1
	Other Current Assets	12.0		13.1
Physical Purchases/Sales	Current PRM	0.8		0.3
	Non-Current PRM	0.2		0.1
Financial Options	Other Current Assets	0.3		0.1
Total		$	13.5	$	13.7
Total Gross Derivatives (A)		$	16.5	$	28.1

(A) See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at June 30, 2011.

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2010 are as follows:

		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	13.3	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		28.8
	Other Current Assets	0.6		0.3
Total		$	13.9	$	29.1
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	—	$	0.1
	Other Current Assets	20.0		19.8
Physical Purchases/Sales	Current PRM	1.4		1.2
	Non-Current PRM	0.8		—
Financial Options	Other Current Assets	0.5		0.7
Total		$	22.7	$	21.8
Total Gross Derivatives (A)		$	36.6	$	50.9

(A) See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2010.

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(2.4	)	$	(3.3	)	$	—
Natural Gas Financial Futures/Swaps	0.1			(7.4		)	—
Total	$	(2.3	)	$	(10.7	)	$	—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(2.9	)
Natural Gas Financial Futures/Swaps	(0.2		)
Total	$	(3.1	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2010.

Derivatives in Cash Flow Hedging Relationships

			Amount Reclassified
	Amount Recognized		from Accumulated Other			Amount
	in Other		Comprehensive Income			Recognized in
(In millions)	Comprehensive Income		into Income			Income
NGLs Financial Options	$	10.5	$	1.1		$	—
NGLs Financial Futures/Swaps	2.0		(0.5		)	—
Natural Gas Financial Futures/Swaps	—		(8.6		)	—
Total	$	12.5	$	(8.0	)	$	—

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(3.7	)
Natural Gas Financial Futures/Swaps	(0.6		)
Total	$	(4.3	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(9.2	)	$	(5.8	)	$	—
Natural Gas Financial Futures/Swaps	(0.1		)	(14.7		)	—
Total	$	(9.3	)	$	(20.5	)	$	—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(5.0	)
Natural Gas Financial Futures/Swaps	(0.4		)
Total	$	(5.4	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2010.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income			into Income			Income
NGLs Financial Options	$	11.0		$	0.5		$	—
NGLs Financial Futures/Swaps	3.3			(1.8		)	—
Natural Gas Financial Futures/Swaps	(9.9		)	(12.0		)	0.1
Total	$	4.4		$	(13.3	)	$	0.1

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(3.8	)
Natural Gas Financial Futures/Swaps	0.2
Total	$	(3.6	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income into income (effective portion) and amounts recognized in income (ineffective portion) for the three and six months ended June 30, 2011 and 2010, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the three and six months ended June 30, 2011 and 2010, if any, are reported in Operating Revenues. 

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, at June 30, 2011, the Company would have been required to post $13.8 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at June 30, 2011.  In addition, the Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

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Retirement Plans and Postretirement Benefit Plans (Details) (USD $) In Millions	6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended				6 Months Ended				3 Months Ended				6 Months Ended				3 Months Ended			6 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Pension Plans, Defined Benefit [Member]	Jun. 30, 2010 Pension Plans, Defined Benefit [Member]	Jun. 30, 2011 Pension Plans, Defined Benefit [Member]	Jun. 30, 2010 Pension Plans, Defined Benefit [Member]	Jun. 30, 2011 Pension Plan [Member]		Jun. 30, 2010 Pension Plan [Member]		Jun. 30, 2011 Pension Plan [Member]		Jun. 30, 2010 Pension Plan [Member]		Jun. 30, 2011 Restoration of Retirement Income Plan [Member]		Jun. 30, 2010 Restoration of Retirement Income Plan [Member]		Jun. 30, 2011 Restoration of Retirement Income Plan [Member]		Jun. 30, 2010 Restoration of Retirement Income Plan [Member]		Jun. 30, 2011 Postretirement Benefit Plans [Member]		Jun. 30, 2010 Postretirement Benefit Plans [Member]	Jun. 30, 2011 Postretirement Benefit Plans [Member]		Jun. 30, 2010 Postretirement Benefit Plans [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost							$ 4.4	[1]	$ 4.0	[1]	$ 8.8	[2]	$ 8.4	[2]	$ 0.2	[1]	$ 0.2	[1]	$ 0.5	[2]	$ 0.4	[2]	$ 0.9	[3]	$ 0.9	$ 1.8	[3]	$ 2.1
Interest cost							8.3	[1]	8.1	[1]	16.6	[2]	15.9	[2]	0.2	[1]	0.1	[1]	0.3	[2]	0.2	[2]	3.1	[3]	4.3	6.2	[3]	8.5
Expected return on plan assets							(11.3)	[1]	(10.5)	[1]	(22.7)	[2]	(21.2)	[2]									(1.3)	[3]	(1.8)	(2.6)	[3]	(3.5)
Amortization of transition obligation																							0.7	[3]	0.7	1.4	[3]	1.4
Amortization of net gains (losses)							4.8	[1]	5.5	[1]	9.6	[2]	10.6	[2]	0.1	[1]	0.1	[1]	0.2	[2]	0.2	[2]	4.5	[3]	3.4	9.1	[3]	6.1
Amortization of unrecognized prior service cost							0.6	[1]	0.6	[1]	1.2	[2]	1.2	[2]	0.2	[1]	0.3	[1]	0.4	[2]	0.4	[2]	(4.1)	[3]	0	(8.2)	[3]	0
Net Periodic Benefit Cost			7.5	8.4	14.9	16.1	6.8	[1]	7.7	[1]	13.5	[2]	14.9	[2]	0.7	[1]	0.7	[1]	1.4	[2]	1.2	[2]	3.8	[3]	7.5	7.7	[3]	14.6
Additional Pension Expense to Meet State Requirements			2.8	1.5	5.3	2.9																	1.7
Pension Plan Funding [Abstract]
Estimated future employer contributions		50
Contributions by employer	40
Estimated employer contributions in current fiscal year	$ 10

[1] In addition to the $7.5 million and $8.4 million of net periodic benefit cost recognized during the three months ended June 30, 2011 and 2010, respectively, OG&E 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).

[2] In addition to the $14.9 million and $16.1 million of net periodic benefit cost recognized during the six months ended June 30, 2011 and 2010, respectively, OG&E 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).

[3] In addition to the $3.8 million and $7.7 million of net periodic benefit cost recognized during the three and six months ended June 30, 2011, respectively, OG&E 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).

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
CURRENT ASSETS
Cash and cash equivalents	$ 5.1	$ 2.3
Accounts receivable, less reserve of $1.7 and $1.9, respectively	324.9	277.9
Accrued unbilled revenues	96.6	56.8
Income taxes receivable	4.7	4.7
Fuel inventories	122.8	158.8
Materials and supplies, at average cost	85.4	83.3
Price risk management	0.9	1.4
Gas imbalances	6.1	2.5
Deferred income taxes	15.1	18.7
Fuel clause under recoveries	22.4	1.0
Other	21.2	24.7
Total current assets	705.2	632.1
OTHER PROPERTY AND INVESTMENTS, at cost	46.9	44.9
PROPERTY, PLANT AND EQUIPMENT
In service	9,414.5	9,188.0
Construction work in progress	774.8	460.0
Total property, plant and equipment	10,189.3	9,648.0
Less accumulated depreciation	3,255.1	3,183.6
Net property, plant and equipment	6,934.2	6,464.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	414.9	489.4
Price risk management	0.2	0.8
Other	34.1	37.5
Total deferred charges and other assets	449.2	527.7
TOTAL ASSETS	8,135.5	7,669.1
CURRENT LIABILITIES
Short-term debt	211.1	145.0
Accounts payable	372.5	321.7
Dividends payable	36.7	36.6
Customer deposits	67.2	67.0
Accrued taxes	42.3	39.3
Accrued interest	54.3	53.1
Accrued compensation	48.9	43.3
Price risk management	12.2	16.8
Gas imbalances	7.7	6.7
Fuel clause over recoveries	9.3	29.9
Other	71.7	55.1
Total current liabilities	933.9	814.5
LONG-TERM DEBT	2,586.8	2,362.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	249.0	372.4
Deferred income taxes	1,512.8	1,434.8
Deferred investment tax credits	7.7	9.4
Regulatory liabilities	215.9	193.1
Price risk management	0.1	0
Deferred revenues	36.2	36.7
Other	44.7	45.3
Total deferred credits and other liabilities	2,066.4	2,091.7
Total liabilities	5,587.1	5,269.1
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	994.7	969.2
Retained earnings	1,434.9	1,380.6
Accumulated other comprehensive loss, net of tax	(41.8)	(60.2)
Total OGE Energy stockholders' equity	2,387.8	2,289.6
Noncontrolling interests	160.6	110.4
Total stockholders' equity	2,548.4	2,400.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 8,135.5	$ 7,669.1

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Organization

The Company 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 conducts these activities through four business segments:  (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  All significant intercompany transactions have been eliminated in consolidation.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC.  OG&E was incorporated in 1902 under the laws of the Oklahoma Territory.  OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enogex is a provider of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting, storing and marketing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.  Enogex's operations are organized into three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. Through OGE Holdings, the Company indirectly owns an 86.7 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company (see Note 3).  The Company continues to consolidate 100 percent of Enogex Holdings in its consolidated financial statements as OGE Energy has a controlling financial interest over the operations of Enogex Holdings.  Prior to November 1, 2010, OER, whose primary operations are in natural gas marketing, was directly owned by OGE Energy.  On November 1, 2010, OGE Energy distributed the equity interests in OER to Enogex LLC.  Accordingly, the discussion that follows includes the results of OER in Enogex's results for all periods presented. Also, Enogex LLC holds a 50 percent ownership interest in Atoka.  The Company has consolidated 100 percent of Atoka in its consolidated financial statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka.

Basis of Presentation

The Condensed Consolidated 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 consolidated 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 Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2010 Form 10-K.

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, OG&E, 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.

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

The following table is a summary of OG&E'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 Consolidated Balance Sheets.

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

As discussed in Note 15 in OG&E'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 OG&E and that the level of retiree medical costs included in base rates will be reviewed and determined in OG&E's next rate case. As a result, OG&E 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.

Reclassifications

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

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Fair Value Measurements, Fair Value Hierarchy (Details) (USD $) In Millions	Jun. 30, 2011		Dec. 31, 2010
Portion Not Subject to Revaluation at Fair Market Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fuel Reserves For Over Retained Fuel Due To Shippers	$ 2.5		$ 3.9
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	1.1		2.2
Commodity Contracts Liabilities	12.3		16.8
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	16.5		36.6
Commodity Contracts Liabilities	28.1		50.9
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	12.3		20.6
Commodity Contracts Liabilities	12.7		20.2
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	1.7		2.7
Commodity Contracts Liabilities	15.4		30.7
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	2.5		13.3
Commodity Contracts Liabilities	0		0
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Netting and Collateral [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	15.4		34.4
Commodity Contracts Liabilities	15.8		34.1
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	6.1	[1]	2.5	[1]
Gas Imbalance Liability Fair Value Disclosure	5.2	[1],[2]	2.8	[1],[2]
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	6.1	[1]	2.5	[1]
Gas Imbalance Liability Fair Value Disclosure	5.2	[1],[2]	2.8	[1],[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	0	[1]	0	[1]
Gas Imbalance Liability Fair Value Disclosure	0	[1],[2]	0	[1],[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	6.1	[1]	2.5	[1]
Gas Imbalance Liability Fair Value Disclosure	5.2	[1],[2]	2.8	[1],[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	0	[1]	0	[1]
Gas Imbalance Liability Fair Value Disclosure	0	[1],[2]	0	[1],[2]
Fair Value, Measurements, Recurring [Member] | Netting and Collateral [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	0	[1]	0	[1]
Gas Imbalance Liability Fair Value Disclosure	$ 0	[1],[2]	$ 0	[1],[2]

[1] The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

[2] Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $2.5 million and $3.9 million at June 30, 2011 and December 31, 2010, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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Common Equity (Tables)

6 Months Ended

Jun. 30, 2011

Equity [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

Basic and diluted earnings per share for the Company were calculated as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2011		2010		2011		2010
Net Income Attributable to OGE Energy	$	103.0	$	77.3	$	127.8	$	101.5
Average Common Shares Outstanding
Basic average common shares outstanding	98.0		97.3		97.8		97.2
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.3		1.4		1.4		1.4
Diluted average common shares outstanding	99.3		98.7		99.2		98.6
Basic Earnings Per Average Common Share
Attributable to OGE Energy Common Shareholders	$	1.05	$	0.79	$	1.31	$	1.04
Diluted Earnings Per Average Common Share
Attributable to OGE Energy Common Shareholders	$	1.04	$	0.78	$	1.29	$	1.03
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Short-Term Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011		Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2009
Line of Credit Facility [Line Items]
Short-term debt	$ 211.1		$ 145.0
Line of Credit Facility [Abstract]
Aggregate Commitment	1,235.0
Cash	5.1		2.3	7.3	58.1
Total	1,240.1
Amount Outstanding	213.3	[1]
Weighted-Average Interest Rate	0.34%
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt	2 years
OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	596.0	[2]
Amount Outstanding	211.1	[1],[2]
Weighted-Average Interest Rate	0.34%	[2],[3]
Maturity	December 6, 2012	[2]
OG&E [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	389.0	[4]
Amount Outstanding	2.2	[1],[4]
Weighted-Average Interest Rate	0.14%	[3],[4]
Maturity	December 6, 2012	[4]
Short Term Borrowing Capacity Thas Has Regulatory Approval	800
Enogex Llc [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	250.0	[5]
Amount Outstanding	$ 0	[1],[5]
Weighted-Average Interest Rate	0.00%	[3],[5]
Maturity	March 31, 2013	[5]

[1] Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2011.

[2] This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  At June 30, 2011, there was $211.1 million in outstanding commercial paper borrowings.

[3] Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

[4] This bank facility is available to back up OG&E'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.

[5] This bank facility is available to provide revolving credit borrowings for Enogex LLC.  As Enogex LLC's credit agreement matures on March 31, 2013, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Condensed Consolidated Balance Sheets.

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Accounting Pronouncements

6 Months Ended

Jun. 30, 2011

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

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 Consolidated Statements of Comprehensive Income after its Condensed Consolidated Statements of Income.

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Fair Value Measurements Carrying and Fair Value Amounts (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Commodity Contract [Member] | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Energy Derivative Contract Assets	$ 1.1	$ 2.2
Energy Derivative Contracts Liabilities	12.3	16.8
Commodity Contract [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Energy Derivative Contract Assets	1.1	2.2
Energy Derivative Contracts Liabilities	12.3	16.8
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	1,903.7	1,655.0
Long-Term Debt, Fair Value	2,115.4	1,831.5
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	99.7	99.7
Long-Term Debt, Fair Value	109.0	106.4
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	135.4	135.4
Long-Term Debt, Fair Value	135.4	135.4
Enogex LLC Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	448.0	447.8
Long-Term Debt, Fair Value	494.2	480.7
Enogex LLC Revolving Credit Agreement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	0	25.0
Long-Term Debt, Fair Value	$ 0	$ 25.0

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

At June 30, 2011, the Company had the following derivative instruments that were designated as cash flow hedges.

	2011 Gross Notional
(In millions)	Volume (A)
Enogex processing hedges
NGLs sales	0.7
Natural gas purchases	2.6
Enogex marketing hedges
Natural gas sales	1.6

(A) Natural gas in Million British thermal unit; NGLs in barrels.

At June 30, 2011, the Company had the following derivative instruments that were not designated as hedging instruments.

(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	15.4	48.5
Fixed Swaps/Futures	55.5	54.3
Options	9.1	10.5
Basis Swaps	9.1	8.4

(A) Natural gas in Million British thermal unit.  

(B) 90.0 percent of the natural gas contracts have durations of one year or less, 6.8 percent have durations of more than one year and less than two years and 3.2 percent have durations of more than two years.

(C) Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

(D) Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at June 30, 2011 are as follows:

		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	2.5	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		14.4
Financial Futures/Swaps	Other Current Assets	0.5		—
Total		$	3.0	$	14.4
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.2	$	0.1
	Other Current Assets	12.0		13.1
Physical Purchases/Sales	Current PRM	0.8		0.3
	Non-Current PRM	0.2		0.1
Financial Options	Other Current Assets	0.3		0.1
Total		$	13.5	$	13.7
Total Gross Derivatives (A)		$	16.5	$	28.1

(A) See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at June 30, 2011.

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2010 are as follows:

		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	13.3	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		28.8
	Other Current Assets	0.6		0.3
Total		$	13.9	$	29.1
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	—	$	0.1
	Other Current Assets	20.0		19.8
Physical Purchases/Sales	Current PRM	1.4		1.2
	Non-Current PRM	0.8		—
Financial Options	Other Current Assets	0.5		0.7
Total		$	22.7	$	21.8
Total Gross Derivatives (A)		$	36.6	$	50.9

(A) See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2010.

Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(2.4	)	$	(3.3	)	$	—
Natural Gas Financial Futures/Swaps	0.1			(7.4		)	—
Total	$	(2.3	)	$	(10.7	)	$	—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(2.9	)
Natural Gas Financial Futures/Swaps	(0.2		)
Total	$	(3.1	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended June 30, 2010.

Derivatives in Cash Flow Hedging Relationships

			Amount Reclassified
	Amount Recognized		from Accumulated Other			Amount
	in Other		Comprehensive Income			Recognized in
(In millions)	Comprehensive Income		into Income			Income
NGLs Financial Options	$	10.5	$	1.1		$	—
NGLs Financial Futures/Swaps	2.0		(0.5		)	—
Natural Gas Financial Futures/Swaps	—		(8.6		)	—
Total	$	12.5	$	(8.0	)	$	—

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(3.7	)
Natural Gas Financial Futures/Swaps	(0.6		)
Total	$	(4.3	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(9.2	)	$	(5.8	)	$	—
Natural Gas Financial Futures/Swaps	(0.1		)	(14.7		)	—
Total	$	(9.3	)	$	(20.5	)	$	—

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(5.0	)
Natural Gas Financial Futures/Swaps	(0.4		)
Total	$	(5.4	)

The following table presents the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the six months ended June 30, 2010.

Derivatives in Cash Flow Hedging Relationships

				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income			into Income			Income
NGLs Financial Options	$	11.0		$	0.5		$	—
NGLs Financial Futures/Swaps	3.3			(1.8		)	—
Natural Gas Financial Futures/Swaps	(9.9		)	(12.0		)	0.1
Total	$	4.4		$	(13.3	)	$	0.1

Derivatives Not Designated as Hedging Instruments

	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(3.8	)
Natural Gas Financial Futures/Swaps	0.2
Total	$	(3.6	)

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Short-Term Debt and Credit Facilities (Tables)

6 Months Ended

Jun. 30, 2011

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The following table provides information regarding the Company's revolving credit agreements and available cash at June 30, 2011.

Revolving Credit Agreements and Available Cash
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	596.0	$	211.1	0.34	%	(D)	December 6, 2012
OG&E (C)	389.0		2.2		0.14	%	(D)	December 6, 2012
Enogex LLC (E)	250.0		—		—	%	(D)	March 31, 2013
	1,235.0		213.3		0.34	%
Cash	5.1		N/A		N/A			N/A
Total	$	1,240.1	$	213.3	0.34	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2011.

(B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  At June 30, 2011, there was $211.1 million in outstanding commercial paper borrowings.

(C) This bank facility is available to back up OG&E'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.

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

(E) This bank facility is available to provide revolving credit borrowings for Enogex LLC.  As Enogex LLC's credit agreement matures on March 31, 2013, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company's Condensed Consolidated Balance Sheets.

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Fair Value Measurements Unobservable Input Reconciliation (Details) (Commodity Contract [Member], USD $) In Millions	3 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2010	Mar. 31, 2010
Commodity Contracts, Assets [Member]
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Level 3 Asset Value, Beginning of Period	$ 5.2	$ 13.3	$ 41.0	$ 49.0
Total gains or losses included in other comprehensive income	(1.0)	(4.8)	7.2	(3.9)
Settlements	(1.7)	(3.3)	(6.1)	(4.1)
Level 3 Asset Value, End of Period	2.5	5.2	42.1	41.0
Commodity Contrtacts, Liabilities [Member]
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation Calculation [Roll Forward]
Level 3 Liability Value, Beginning of Period	0	0	8.2	14.7
Total gains or losses included in other comprehensive income	0	0	(3.7)	(5.1)
Settlements	0	0	(2.7)	(1.4)
Level 3 Liability Value, End of Period	$ 0	$ 0	$ 1.8	$ 8.2

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Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2011

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]

The following table summarizes the components of accumulated other comprehensive loss at June 30, 2011 and December 31, 2010 attributable to OGE Energy.  At both June 30, 2011 and December 31, 2010, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka.

	June 30,			December 31,
(In millions)	2011			2010
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	(30.1	)	$	(31.1	)
Prior service cost	(0.3		)	(0.5		)
Postretirement plans:
Net loss	(12.8		)	(13.6		)
Prior service cost	9.8			—
Net transition obligation	(0.2		)	(0.3		)
Deferred commodity contracts hedging losses	(12.5		)	(19.5		)
Deferred interest rate swaps hedging losses	(0.8		)	(1.0		)
Total accumulated other comprehensive loss	(46.9		)	(66.0		)
Less:  Accumulated other comprehensive loss attributable to noncontrolling interests	(5.1		)	(5.8		)
Accumulated other comprehensive loss, net of tax	$	(41.8	)	$	(60.2	)

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Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

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

OG&E 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, OG&E is obligated to repurchase such unremarketed bonds.  As OG&E 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 Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

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

OG&E Issuance of New Long-Term Debt

On May 24, 2011, OG&E 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. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.

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ArcLight Transaction

6 Months Ended

Jun. 30, 2011

Noncontrolling Interest [Abstract]

ArcLight Transaction

ArcLight Transaction

The following table summarizes changes in OGE Energy's equity attributable to changes in its ownership interest in Enogex Holdings during the six months ended June 30, 2011. There were no contributions by OGE Energy or the ArcLight group to fund Enogex LLC's 2011 capital requirements during the three months ended June 30, 2011. Also, there were no sales of additional membership interests in Enogex Holdings to the ArcLight group during the three months ended June 30, 2011.

(In millions)
Net income attributable to OGE Energy	$	127.8
Transfers (to) from the noncontrolling interest
Increase in paid-in capital for sale of 100,000 units of Enogex Holdings	0.9
Increase in paid-in capital for issuance of 4,303,007 units of Enogex Holdings	28.2
Decrease in paid-in capital for deferred income taxes attributable to the sale and issuance of units
of Enogex Holdings	(11.2		)
Net transfers from the noncontrolling interest	17.9
Change from net income attributable to OGE Energy and transfers from noncontrolling interest	$	145.7

The following table summarizes changes in OGE Holdings' and the ArcLight group's membership interest in Enogex Holdings for the six months ended June 30, 2011. Prior to November 1, 2010, Enogex Holdings was wholly owned by OGE Energy.

(In millions)	OGE Holdings		ArcLight group		Total
Balance at December 31, 2010 (units)	90.1		9.9		100.0
Ownership percentage at December 31, 2010	90.1	%	9.9	%	100.0	%
Sale of 100,000 units of Enogex Holdings (A)	(0.1	)	0.1		—
Issuance of 4,303,007 units of Enogex Holdings (B)	0.4		3.9		4.3
Balance at June 30, 2011 (units)	90.4		13.9		104.3
Ownership percentage at June 30, 2011	86.7	%	13.3	%	100.0	%

(A) On February 1, 2011, OGE Energy sold a 0.1 percent membership interest in Enogex Holdings to the ArcLight group for $1.9 million.

(B) In February 2011, OGE Energy and the ArcLight group made contributions of $8.0 million and $71.6 million, respectively, to fund a portion of Enogex LLC's 2011 capital requirements.

Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings makes quarterly distributions to its partners. The below table summarizes these distributions during the six months ended June 30, 2011.

	OGE Holdings		ArcLight group's
(In millions)	Portion		Portion		Total Distribution
First quarter 2011	$	7.5	$	0.8	$	8.3
Second quarter 2011	34.3		5.3		39.6
Total	$	41.8	$	6.1	$	47.9

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Report of Business Segments

6 Months Ended

Jun. 30, 2011

Segment Reporting [Abstract]

Report of Business Segments

Report of Business Segments

The Company's business is divided into four segments for financial reporting purposes.  These segments are as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  Other Operations primarily includes the operations of the holding company.  Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.  In reviewing its segment operating results, the Company focuses on operating income as its measure of segment profit and loss, and, therefore, has presented this information below.  The following tables summarize the results of the Company's business segments for the three and six months ended June 30, 2011 and 2010.

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
June 30, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	568.7	$	108.0	$	289.1	$	168.3		$	—		$	(156.0	)	$	978.1
Cost of goods sold	254.3		69.5		210.9		170.4			—			(155.0		)	550.1
Gross margin on revenues	314.4		38.5		78.2		(2.1		)	—			(1.0		)	428.0
Other operation and maintenance	110.2		13.0		26.3		2.0			(4.2		)	(0.7		)	146.6
Depreciation and amortization	52.1		5.8		13.4		0.1			3.3			—			74.7
Taxes other than income	18.8		3.3		1.7		(0.1		)	0.8			—			24.5
Operating income (loss)	$	133.3	$	16.4	$	36.8	$	(4.1	)	$	0.1		$	(0.3	)	$	182.2
Total assets	$	6,290.5	$	2,297.3	$	1,106.7	$	80.2		$	2,937.3		$	(4,576.5	)	$	8,135.5

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
June 30, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	512.8	$	97.1	$	235.4	$	189.0		$	—		$	(147.1	)	$	887.2
Cost of goods sold	230.8		60.9		168.6		192.9			—			(146.7		)	506.5
Gross margin on revenues	282.0		36.2		66.8		(3.9		)	—			(0.4		)	380.7
Other operation and maintenance	101.2		12.6		23.5		2.1			(3.5		)	(0.9		)	135.0
Depreciation and amortization	50.6		5.4		12.5		—			2.7			—			71.2
Taxes other than income	17.2		3.4		1.6		—			0.8			—			23.0
Operating income (loss)	$	113.0	$	14.8	$	29.2	$	(6.0	)	$	—		$	0.5		$	151.5
Total assets	$	5,775.9	$	1,585.2	$	907.9	$	104.5		$	2,691.6		$	(3,771.0	)	$	7,294.1

			Transportation		Gathering
Six Months Ended	Electric		and		and					Other
June 30, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	990.8	$	208.2	$	555.8	$	366.4		$	—		$	(302.6	)	$	1,818.6
Cost of goods sold	473.7		133.5		407.2		369.7			—			(300.8		)	1,083.3
Gross margin on revenues	517.1		74.7		148.6		(3.3		)	—			(1.8		)	735.3
Other operation and maintenance	216.0		22.1		53.1		4.1			(8.9		)	(1.5		)	284.9
Depreciation and amortization	103.9		11.2		26.9		0.1			6.6			—			148.7
Taxes other than income	37.9		7.6		3.6		0.1			2.4			—			51.6
Operating income (loss)	$	159.3	$	33.8	$	65.0	$	(7.6	)	$	(0.1	)	$	(0.3	)	$	250.1
Total assets	$	6,290.5	$	2,297.3	$	1,106.7	$	80.2		$	2,937.3		$	(4,576.5	)	$	8,135.5

			Transportation		Gathering
Six Months Ended	Electric		and		and					Other
June 30, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)
Operating revenues	$	956.8	$	208.2	$	483.3	$	434.7		$	—		$	(320.0	)	$	1,763.0
Cost of goods sold	481.6		127.1		348.6		437.2			—			(317.9		)	1,076.6
Gross margin on revenues	475.2		81.1		134.7		(2.5		)	—			(2.1		)	686.4
Other operation and maintenance	195.1		23.6		44.8		4.8			(7.6		)	(2.1		)	258.6
Depreciation and amortization	100.3		10.8		24.9		—			5.5			—			141.5
Taxes other than income	34.9		7.3		3.5		0.2			2.1			—			48.0
Operating income (loss)	$	144.9	$	39.4	$	61.5	$	(7.5	)	$	—		$	—		$	238.3
Total assets	$	5,775.9	$	1,585.2	$	907.9	$	104.5		$	2,691.6		$	(3,771.0	)	$	7,294.1

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ArcLight Transaction Distributions Made to Partners (Details) (Cash Distribution [Member], USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2011
Distribution Made to Partners [Line Items]
Distributions to partners	$ 39.6	$ 8.3	$ 47.9
OGE Holdings [Member]
Distribution Made to Partners [Line Items]
Distributions to partners	34.3	7.5	41.8
Enogex Holdings [Member]
Distribution Made to Partners [Line Items]
Distributions to partners	$ 5.3	$ 0.8	$ 6.1

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2011

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

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 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	$	1.9	$	1.5	$	3.7	$	3.1
Earnings per share	0.8		0.4		3.0		0.8
Total performance units	2.7		1.9		6.7		3.9
Restricted stock	0.2		0.3		0.5		0.4
Total compensation expense	$	2.9	$	2.2	$	7.2	$	4.3
Income tax benefit	$	1.1	$	0.9	$	2.8	$	1.6

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

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

	Shares	Fair Value
Grants
Restricted stock	829	$50.61

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 139.0	$ 103.1
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	148.7	141.5
Deferred income taxes and investment tax credits, net	60.3	52.2
Allowance for equity funds used during construction	(10.2)	(4.6)
(Gain) loss on disposition and abandonment of assets	(3.3)	0.9
Stock-based compensation expense	0.4	2.3
Price risk management assets	1.1	(4.4)
Price risk management liabilities	6.8	11.4
Regulatory assets	6.8	6.8
Regulatory liabilities	3.3	(6.5)
Other assets	5.4	6.2
Other liabilities	(38.3)	(34.2)
Change in certain current assets and liabilities
Accounts receivable, net	(47.0)	(24.1)
Accrued unbilled revenues	(39.8)	(24.4)
Income taxes receivable	0	150.6
Fuel, materials and supplies inventories	33.9	(28.5)
Gas imbalance assets	(3.6)	(1.8)
Fuel clause under recoveries	(21.4)	(0.6)
Other current assets	3.5	8.9
Accounts payable	(6.1)	4.8
Gas imbalance liabilities	1.0	(4.2)
Fuel clause over recoveries	(20.6)	(50.1)
Other current liabilities	26.6	36.2
Net Cash Provided from Operating Activities	246.5	341.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(571.8)	(306.2)
Reimbursement of capital expenditures	21.6	12.9
Proceeds from sale of assets	17.5	1.7
Net Cash Used in Investing Activities	(532.7)	(291.6)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	246.3	246.2
Contributions from noncontrolling interest partners	73.5	0
Increase (decrease) in short-term debt	66.1	(62.1)
Issuance of common stock	7.5	9.8
Proceeds from line of credit	0	115.0
Retirement of long-term debt	0	(289.2)
Distributions to noncontrolling interest partners	(6.1)	0
Repayment of line of credit	(25.0)	(50.0)
Dividends paid on common stock	(73.3)	(70.4)
Net Cash Provided from (Used in) Financing Activities	289.0	(100.7)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	2.8	(50.8)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2.3	58.1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 5.1	$ 7.3

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except as set forth below and in Note 15, the circumstances set forth in Notes 14 and 15 to the Company's Consolidated 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.

OG&E Railcar Lease Agreement

OG&E has a noncancellable operating lease with purchase options, covering 1,446 coal hopper railcars to transport coal from Wyoming to OG&E's coal-fired generation units.  Rental payments are charged to Fuel Expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011.  At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease.  If OG&E 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, OG&E would be responsible for the difference in those values up to a maximum of $23.7 million.

On February 10, 2009, OG&E 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.

OG&E 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.

OG&E Wind Power Purchase Commitment

As previously disclosed, OG&E 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 OG&E will purchase its electric output.

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 Consolidated Financial Statements.  Except as otherwise stated above, in Note 15 below, in Item 1 of Part II of this Form 10-Q, in Notes 14 and 15 of Notes to Consolidated 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 consolidated financial position, results of operations or cash flows.

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Derivative Instruments and Hedging Activities, Balance Sheet Presentation Related to Derivative Instruments (Details) (Enogex [Member], USD $) In Millions	Jun. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Assets	$ 16.5	[1]	$ 36.6	[2]
Liabilities	28.1	[1]	50.9	[2]
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	3.0		13.9
Liabilities	14.4		29.1
Designated as Hedging Instrument [Member] | NGL [Member] | Options [Member] | Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	2.5		13.3
Liabilities	0		0
Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	0		0
Liabilities	14.4		28.8
Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Assets	0.5		0.6
Liabilities	0		0.3
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	13.5		22.7
Liabilities	13.7		21.8
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Physical [Member] | Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	0.8		1.4
Liabilities	0.3		1.2
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Physical [Member] | Noncurrent PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	0.2		0.8
Liabilities	0.1		0
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	0.2		0
Liabilities	0.1		0.1
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Assets	12.0		20.0
Liabilities	13.1		19.8
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Options [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Assets	0.3		0.5
Liabilities	$ 0.1		$ 0.7

[1] See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at June 30, 2011.

[2] See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2010.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2011

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Policy [Policy Text Block]

Organization

The Company 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 conducts these activities through four business segments:  (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing.  All significant intercompany transactions have been eliminated in consolidation.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC.  OG&E was incorporated in 1902 under the laws of the Oklahoma Territory.  OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enogex is a provider of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting, storing and marketing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.  Enogex's operations are organized into three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. Through OGE Holdings, the Company indirectly owns an 86.7 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company (see Note 3).  The Company continues to consolidate 100 percent of Enogex Holdings in its consolidated financial statements as OGE Energy has a controlling financial interest over the operations of Enogex Holdings.  Prior to November 1, 2010, OER, whose primary operations are in natural gas marketing, was directly owned by OGE Energy.  On November 1, 2010, OGE Energy distributed the equity interests in OER to Enogex LLC.  Accordingly, the discussion that follows includes the results of OER in Enogex's results for all periods presented. Also, Enogex LLC holds a 50 percent ownership interest in Atoka.  The Company has consolidated 100 percent of Atoka in its consolidated financial statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka.

Basis of Accounting [Text Block]

Basis of Presentation

The Condensed Consolidated 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 consolidated 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 Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2010 Form 10-K.

Public Utilities, Policy [Policy Text Block]

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, OG&E, 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.

OG&E 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.

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.

Reclassifications [Text Block]

Reclassifications

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

Fair Value of Financial Instruments, Policy [Policy Text Block]

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 and examples of each 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. Instruments classified as Level 1 include natural gas futures, swaps and option transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

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 over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing.

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).  Instruments classified as Level 3 include NGLs options.

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.  The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining.  Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.  Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, NGLs options contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management's best estimate of fair value.  These contracts are classified as Level 3.

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

The carrying value of the financial instruments on the Condensed Consolidated 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.  However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values.  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.

Derivatives, Offsetting Fair Value Amounts, Policy [Policy Text Block]

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset.  The reporting entity's choice to offset or not must be applied consistently.  A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets.  The Company has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

Derivatives, Policy [Policy Text Block]

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated 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) commodity contracts for the purchase and sale of natural gas used in or produced by its operations, (ii) commodity contracts for the sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.  Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

Cash Flow Hedges

For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings.  The ineffective portion of a derivative's change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument.  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.

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing, pipeline and storage operations (operational gas hedges).  The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions.

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.

Derivatives Not Designated As Hedging Instruments

Derivative instruments not designated as hedging instruments are utilized in OER's asset management, marketing and trading activities.  For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Income Tax, Policy [Policy Text Block]

Income Taxes

The Company 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.  OG&E earns both Federal and Oklahoma state tax credits associated with the production from its wind farms.  In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Share

Basic earnings per share is calculated by dividing net income attributable to OGE Energy by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units.

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CONDENSED CONSOLIDATED BALANCE SHEETS PARENTHETICAL (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
CURRENT ASSETS
Accounts receivable reserve	$ 1.7	$ 1.9

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company 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.  OG&E earns both Federal and Oklahoma state tax credits associated with the production from its wind farms.  In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

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Rate Matters and Regulation (Details) (USD $) In Millions, unless otherwise specified			3 Months Ended					3 Months Ended
	Jun. 30, 2011 OG&E Wholesale Agreement [Member]	Jun. 30, 2011 OG&E Crossroads Wind Project [Member] megawatt	Jun. 30, 2011 OG&E Long-Term Gas Supply Agreements [Member] agreements	Jun. 30, 2011 OG&E 2010 Arkansas Rate Case Filing [Member]	Sep. 28, 2010 OG&E 2010 Arkansas Rate Case Filing [Member]	Jun. 30, 2011 OG&E SPP Cost Tracker [Member]	Jun. 30, 2011 OG&E FERC Transmission Rate Incentive Filing [Member] transmissions	Jun. 30, 2011 OG&E Demand and Energy Efficiency Program Filing [Member]	Jun. 30, 2011 Review of OG&E's Fuel Adjustment Clause for Calendar Year 2009 [Member]	Jun. 30, 2011 OG&E Smart Grid Project [Member]	Jun. 30, 2011 OG&E 2011 Oklahoma Rate Case Filing [Member]
Regulatory Matters [Line Items]
Customer Contract Contribution to OG&E's Gross Margin for 2010	$ 17.4
Customer Contract Percentage Contribution to OG&E's Gross Margin for 2010	1.50%
Customer Contract Additional Gross Margin Expected in The Next Fiscal Year	4.0
Wind Farm Capacity (megawatts)		227.5
Amount of Regulatory Costs Approved					17.7			7.0
Long Term Purchase Commitment Number of Agreements			4
Long-term Purchase Commitment, Time Period			12 years					3 years
Long Term Purchase Commitment Percent of Current Supply Needs			25.00%
Requested Rate Dollar Increase											73.3
Recovery Of And Return On Significant Electric System Expansions and Upgrades and Increased Operating Costs				8.8
Recovery of Actual Costs of Third Party Transmission Charges and SPP Administration Fees				1.0
Maximum Deferral of Certan Expenses Associated with Customer Educational Program not to Exceed Two Years				0.3
Maximum Length of Deferred Expenses to be Expended				2 years
Anticipated Recovery of Incremental Revenues						1.8
Percent of Requested Recovery of Incurred Construction Costs							100.00%
Number of Projects Requested Under Incentive Program							5
Expected Increase in Residential Electric Bill								1.47
Customer Refund Requested Related to Regulatory Matters									15.5
Expected Capital Expenditures Net of Governmental Funds Received										14
Requested Rate Percentage Increase											4.30%
Requested Return on Equity											11.00%
Common Equity Percentage in Determining Return on Equity											53.00%
Incremental Change in Return on Equity											0.10%
Effect of Return on Equity Change on Requested Rate Increase											3.0
New Capital Investments											$ 500

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Retirement Plans and Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2011

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The details of net periodic benefit cost of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated 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	$	4.4		$	4.0		$	8.8		$	8.4
Interest cost	8.3			8.1			16.6			15.9
Expected return on plan assets	(11.3		)	(10.5		)	(22.7		)	(21.2		)
Amortization of net loss	4.8			5.5			9.6			10.6
Amortization of unrecognized prior service cost	0.6			0.6			1.2			1.2
Net periodic benefit cost	$	6.8		$	7.7		$	13.5		$	14.9

	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)
Service cost	$	0.2	$	0.2	$	0.5	$	0.4
Interest cost	0.2		0.1		0.3		0.2
Amortization of net loss	0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost	0.2		0.3		0.4		0.4
Net periodic benefit cost	$	0.7	$	0.7	$	1.4	$	1.2

(A) In addition to the $7.5 million and $8.4 million of net periodic benefit cost recognized during the three months ended June 30, 2011 and 2010, respectively, OG&E 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 $14.9 million and $16.1 million of net periodic benefit cost recognized during the six months ended June 30, 2011 and 2010, respectively, OG&E 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).

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011 (C)			2010			2011 (C)			2010
Service cost	$	0.9		$	0.9		$	1.8		$	2.1
Interest cost	3.1			4.3			6.2			8.5
Expected return on plan assets	(1.3		)	(1.8		)	(2.6		)	(3.5		)
Amortization of transition obligation	0.7			0.7			1.4			1.4
Amortization of net loss	4.5			3.4			9.1			6.1
Amortization of unrecognized prior service cost	(4.1		)	—			(8.2		)	—
Net periodic benefit cost	$	3.8		$	7.5		$	7.7		$	14.6

(C) In addition to the $3.8 million and $7.7 million of net periodic benefit cost recognized during the three and six months ended June 30, 2011, respectively, OG&E 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).

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Retirement Plans and Postretirement Benefit Plans

6 Months Ended

Jun. 30, 2011

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Retirement Plans and Postretirement Benefit Plans

12. Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated 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	$	4.4		$	4.0		$	8.8		$	8.4
Interest cost	8.3			8.1			16.6			15.9
Expected return on plan assets	(11.3		)	(10.5		)	(22.7		)	(21.2		)
Amortization of net loss	4.8			5.5			9.6			10.6
Amortization of unrecognized prior service cost	0.6			0.6			1.2			1.2
Net periodic benefit cost	$	6.8		$	7.7		$	13.5		$	14.9

	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)
Service cost	$	0.2	$	0.2	$	0.5	$	0.4
Interest cost	0.2		0.1		0.3		0.2
Amortization of net loss	0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost	0.2		0.3		0.4		0.4
Net periodic benefit cost	$	0.7	$	0.7	$	1.4	$	1.2

(A) In addition to the $7.5 million and $8.4 million of net periodic benefit cost recognized during the three months ended June 30, 2011 and 2010, respectively, OG&E 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 $14.9 million and $16.1 million of net periodic benefit cost recognized during the six months ended June 30, 2011 and 2010, respectively, OG&E 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).

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011 (C)			2010			2011 (C)			2010
Service cost	$	0.9		$	0.9		$	1.8		$	2.1
Interest cost	3.1			4.3			6.2			8.5
Expected return on plan assets	(1.3		)	(1.8		)	(2.6		)	(3.5		)
Amortization of transition obligation	0.7			0.7			1.4			1.4
Amortization of net loss	4.5			3.4			9.1			6.1
Amortization of unrecognized prior service cost	(4.1		)	—			(8.2		)	—
Net periodic benefit cost	$	3.8		$	7.5		$	7.7		$	14.6

(C) In addition to the $3.8 million and $7.7 million of net periodic benefit cost recognized during the three and six months ended June 30, 2011, respectively, OG&E 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

The Company previously disclosed in its 2010 Form 10-K that it may contribute up to $50 million to its Pension Plan during 2011.  During the six months ended June 30, 2011, the Company contributed $40 million to its Pension Plan and 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.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
OPERATING REVENUES
Electric Utility operating revenues	$ 568.7	$ 512.8	$ 990.8	$ 956.8
Natural Gas Midstream Operations operating revenues	409.4	374.4	827.8	806.2
Total operating revenues	978.1	887.2	1,818.6	1,763.0
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	242.5	218.9	450.0	457.8
Natural Gas Midstream Operations cost of goods sold	307.6	287.6	633.3	618.8
Total cost of goods sold	550.1	506.5	1,083.3	1,076.6
Gross margin on revenues	428.0	380.7	735.3	686.4
OPERATING EXPENSES
Other operation and maintenance	146.6	135.0	284.9	258.6
Depreciation and amortization	74.7	71.2	148.7	141.5
Taxes other than income	24.5	23.0	51.6	48.0
Total operating expenses	245.8	229.2	485.2	448.1
OPERATING INCOME	182.2	151.5	250.1	238.3
OTHER INCOME (EXPENSE)
Interest income	0.1	0	0.2	0
Allowance for equity funds used during construction	5.8	2.3	10.2	4.6
Other income	7.0	3.4	13.3	6.5
Other expense	(3.5)	(5.0)	(5.8)	(7.4)
Net other income	9.4	0.7	17.9	3.7
INTEREST EXPENSE
Interest on long-term debt	35.8	33.4	71.2	67.0
Allowance for borrowed funds used during construction	(2.9)	(1.0)	(5.2)	(2.2)
Interest on short-term debt and other interest charges	1.6	1.6	2.6	3.3
Interest expense	34.5	34.0	68.6	68.1
INCOME BEFORE TAXES	157.1	118.2	199.4	173.9
INCOME TAX EXPENSE	47.8	40.3	60.4	70.8
NET INCOME	109.3	77.9	139.0	103.1
Less: Net income attributable to noncontrolling interests	6.3	0.6	11.2	1.6
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$ 103.0	$ 77.3	$ 127.8	$ 101.5
BASIC AVERAGE COMMON SHARES OUTSTANDING (in shares)	98.0	97.3	97.8	97.2
DILUTED AVERAGE COMMON SHARES OUTSTANDING (in shares)	99.3	98.7	99.2	98.6
BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS (in dollars per share)	$ 1.05	$ 0.79	$ 1.31	$ 1.04
DILUTED EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS (in dollars per share)	$ 1.04	$ 0.78	$ 1.29	$ 1.03
DIVIDENDS DECLARED PER COMMON SHARE (in dollars per share)	$ 0.3750	$ 0.3625	$ 0.7500	$ 0.7250

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Summary of Significant Accounting Policies, Equity Ownership (Details)	6 Months Ended
	Jun. 30, 2011
Enogex Holdings [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	86.70%
Noncontrolling Interest Consolidation Percentage	100.00%
Atoka [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Noncontrolling Interest Consolidation Percentage	100.00%

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Common Equity Earnings Per Share (Details) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Equity [Abstract]
Net Income Attributable to OGE Energy	$ 103.0	$ 77.3	$ 127.8	$ 101.5
Basic Average Common Shares Outstanding	98.0	97.3	97.8	97.2
Contingently Issuable Shares (Performance Units)	1.3	1.4	1.4	1.4
Diluted Average Common Shares Outstanding	99.3	98.7	99.2	98.6
Earnings Per Share, Basic and Diluted [Abstract]
Earnings Per Share, Basic	$ 1.05	$ 0.79	$ 1.31	$ 1.04
Earnings Per Share, Diluted	$ 1.04	$ 0.78	$ 1.29	$ 1.03
Anti-dilutive shares excluded from earnings per share calculation	0	0	0	0

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Derivative Instruments and Hedging Activities, Income Statement Presentation Related to Derivative Instruments (Details) (Enogex [Member], USD $) In Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010	Jun. 30, 2011		Jun. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 18.8
Additional Collateral, Aggregate Fair Value	13.8			13.8
Natural Gas Liquids [Member] | Fixed Swaps/Futures [Member] | Operating Revenues [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Reclassifed from Accumulated OCI into Income			(0.5)			(1.8)
Amount Recognized in Income			0			0
Natural Gas Liquids [Member] | Fixed Swaps/Futures [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in OCI			2.0			3.3
Natural Gas Liquids [Member] | Options [Member] | Operating Revenues [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Reclassifed from Accumulated OCI into Income	(3.3)		1.1	(5.8)		0.5
Amount Recognized in Income	0		0	0		0
Natural Gas Liquids [Member] | Options [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in OCI	(2.4)	[1]	10.5	(9.2)	[2]	11.0
Natural gas [Member] | Physical [Member] | Operating Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Income	(2.9)		(3.7)	(5.0)		(3.8)
Natural gas [Member] | Fixed Swaps/Futures [Member] | Operating Revenues [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Reclassifed from Accumulated OCI into Income	(7.4)		(8.6)	(14.7)		(12.0)
Amount Recognized in Income	0		0	0		0.1
Natural gas [Member] | Fixed Swaps/Futures [Member] | Operating Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Income	(0.2)		(0.6)	(0.4)		0.2
Natural gas [Member] | Fixed Swaps/Futures [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in OCI	0.1	[1]	0	(0.1)	[2]	(9.9)
Operating Revenues [Member] | Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Reclassifed from Accumulated OCI into Income	(10.7)		(8.0)	(20.5)		(13.3)
Amount Recognized in Income	0		0	0		0.1
Operating Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Income	(3.1)		(4.3)	(5.4)		(3.6)
Cash Flow Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in OCI	$ (2.3)	[1]	$ 12.5	$ (9.3)	[2]	$ 4.4

[1] The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

[2] The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $18.8 million.

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Stock-Based Compensation (Details) (USD $) In Millions, except Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	$ 2.9	$ 2.2	$ 7.2	$ 4.3
Income tax benefit from compensation expense	1.1	0.9	2.8	1.6
Stock-Based Compensation Activity
Shares Issued in Period	1,829		267,045
Shares Paid for Tax Withholding for Share Based Compensation	2,660		2,660
Cash Received from Exercise of Stock Options	0.1		0.8
Tax Benefit Realized from Exercise of Stock Options	0.1		0.2
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	2.7	1.9	6.7	3.9
Total Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	1.9	1.5	3.7	3.1
Performance Units Related to Earnings Per Share [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	0.8	0.4	3.0	0.8
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	$ 0.2	$ 0.3	$ 0.5	$ 0.4
Stock-Based Compensation Activity
Restricted Stock Granted - Number of Shares	829
Restricted Stock Granted - Fair Value	$ 50.61

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011 coalhopperrailcars railcars
Loss Contingencies [Line Items]
Railcars under Noncancellable Operating Lease with Purchase Options	1,446
Railcars Under Short Term Lease	270
Railcars Under Short Term Lease Coverd by Initial Expiration	135
Railcars Under Short Term Lease Under Month to Month Basis	135
OG&E Railcar Lease Agreement [Member]
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Maximum	$ 23.7

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Summary of Significant Accounting Policies, Regulated Operations (Details) (USD $) In Millions			3 Months Ended
	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Jun. 30, 2011 Fuel clause under recoveries [Member]	Dec. 31, 2010 Fuel clause under recoveries [Member]	Jun. 30, 2011 Benefit obligations regulatory asset [Member]	Dec. 31, 2010 Benefit obligations regulatory asset [Member]	Jun. 30, 2011 Income taxes recoverable from customers, net [Member]	Dec. 31, 2010 Income taxes recoverable from customers, net [Member]	Jun. 30, 2011 Deferred storm expenses [Member]	Dec. 31, 2010 Deferred storm expenses [Member]	Jun. 30, 2011 Smart Grid [Member]	Dec. 31, 2010 Smart Grid [Member]	Jun. 30, 2011 Unamortized loss on reacquired debt [Member]	Dec. 31, 2010 Unamortized loss on reacquired debt [Member]	Jun. 30, 2011 Deferred Pension Plan expenses [Member]	Dec. 31, 2010 Deferred Pension Plan expenses [Member]	Jun. 30, 2011 Red Rock deferred expenses [Member]	Dec. 31, 2010 Red Rock deferred expenses [Member]	Jun. 30, 2011 Other [Member]		Dec. 31, 2010 Other [Member]		Jun. 30, 2011 Fuel clause over recoveries [Member]	Dec. 31, 2010 Fuel clause over recoveries [Member]	Jun. 30, 2011 Accrued removal obligations, net [Member]	Dec. 31, 2010 Accrued removal obligations, net [Member]	Jun. 30, 2011 Pension tracker [Member]	Dec. 31, 2010 Pension tracker [Member]	Jun. 30, 2011 Other [Member]		Dec. 31, 2010 Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Additional Pension Expense to Meet State Requirements			$ 1.7
Regulatory Assets, Current	32.6	5.9		22.4	1.0															10.2	[1]	4.9	[1]
Regulatory Assets, Non - Current	414.9	489.4				279.7	365.5	48.7	43.3	27.4	28.6	22.5	14.2	14.8	15.3	11.3	13.5	7.0	7.2	3.5		1.8
Regulatory Liability, Current	37.7	50.8																						9.3	29.9					28.4	[2]	20.9	[2]
Regulatory Liability, Non - Current	$ 215.9	$ 193.1																								$ 200.7	$ 184.9	$ 15.2	$ 8.2

[1] Included in Other Current Assets on the Condensed Consolidated Balance Sheets.

[2] Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.