10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period endedJune 30, 2013

OR

oTRANSITION 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.þ  Yes  o  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).þ  Yes  o  No

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).o  Yes   þ  No

At July 15, 2013, there were 198,353,947 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDEDJUNE 30, 2013

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	48
Item 4. Controls and Procedures	48
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	49
Item 1A. Risk Factors	49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 6. Exhibits	50
Signature	51

i

GLOSSARY OF TERMS

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

Abbreviation	Definition
2012 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2012
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
BART	Best available retrofit technology
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
Company	OGE Energy, collectively with its subsidiaries
DOJ	U.S. Department of Justice
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
Enable Midstream Partners	Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC	Enogex LLC, collectively with its subsidiaries
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FIP	Federal implementation plan
GAAP	Accounting principles generally accepted in the United States
MRT	CenterPoint Energy - Mississippi River Transmission, LLC, a Delaware limited liability company
NGLs	Natural gas liquids
NOX	Nitrogen oxide
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
Off-system sales	Sales to other utilities and power marketers
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings (prior to May 1, 2013)
Pension Plan	Qualified defined benefit retirement plan
PRM	Price risk management
PSO	Public Service Company of Oklahoma
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

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," areforward-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 materiallyfrom those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" in the Company's 2012Form 10-K and "Item 1A. Risk Factors" and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factorsthat could cause actual results to differ materiallyfrom the forward-looking statementsinclude, 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 ofthe Company and its subsidiariesto access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

• prices and availability of electricity, coal, natural gasand NGLs;

• the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regionsEnable Midstream Partnersserves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity onEnable Midstream Partners' interstate pipelines;

• the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering byEnable Midstream Partners' gathering and processing business and transporting byEnable Midstream Partners' interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regionsEnable Midstream Partnersserves;

• business conditions in the energyand natural gas midstream industries;

• competitive factors including the extent and timing of the entry of additional competition in the markets served bythe 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 entersthe Company'smarkets;

• environmental laws and regulations that may impactthe Company'soperations;

• changes in accounting standards, rules or guidelines;

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

• the cost of protecting assets against, or damage due to, terrorism or cyber-attacks and other catastrophic events;

• advances in technology;

• creditworthiness of suppliers, customers and other contractual parties;

• difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment inEnable Midstream Partners that the Company does not control;

• the risk that Enable Midstream Partners may not be able to successfully integrate the operations of Enogex LLC and the businesses contributed by CenterPoint as discussed in Note 3; and

• other risk factors listed in the reports filed bythe Companywith the Securities and Exchange Commission including those listed in"Item 1A.Risk Factors" andinExhibit 99.01 tothe Company's2012 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)	2013			2012			2013			2012
OPERATING REVENUES
Electric Utility operating revenues	$	574.6		$	528.0		$	1,030.1		$	954.7
Natural Gas Midstream Operations operating revenues (Note 1)	159.6			327.0			605.5			741.0
Total operating revenues	734.2			855.0			1,635.6			1,695.7
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	242.8			192.7			442.2			376.3
Natural Gas Midstream Operations cost of goods sold (Note 1)	127.8			216.6			481.4			518.3
Total cost of goods sold	370.6			409.3			923.6			894.6
Gross margin on revenues	363.6			445.7			712.0			801.1
OPERATING EXPENSES
Other operation and maintenance	122.0			153.0			270.0			300.6
Depreciation and amortization	74.4			90.5			166.3			177.1
Impairment of assets	—			0.1			—			0.3
Gain on insurance proceeds	—			—			—			(7.5		)
Taxes other than income	23.3			24.8			56.4			55.0
Total operating expenses	219.7			268.4			492.7			525.5
OPERATING INCOME	143.9			177.3			219.3			275.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates (Note 1)	18.5			—			18.5			—
Allowance for equity funds used during construction	1.5			1.7			2.7			3.6
Other income	4.5			2.5			19.2			10.2
Other expense	(4.2		)	(3.6		)	(10.7		)	(5.5		)
Net other income	20.3			0.6			29.7			8.3
INTEREST EXPENSE
Interest on long-term debt	36.0			38.9			75.7			78.1
Allowance for borrowed funds used during construction	(0.7		)	(0.9		)	(1.4		)	(2.0		)
Interest on short-term debt and other interest charges	2.0			2.4			4.2			4.4
Interest expense	37.3			40.4			78.5			80.5
INCOME BEFORE TAXES	126.9			137.5			170.5			203.4
INCOME TAX EXPENSE	33.9			35.9			49.5			54.3
NET INCOME	93.0			101.6			121.0			149.1
Less: Net income attributable to noncontrolling interests	1.3			7.7			6.2			18.1
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	91.7		$	93.9		$	114.8		$	131.0
BASIC AVERAGE COMMON SHARES OUTSTANDING	198.3			197.2			198.0			196.8
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.4			197.8			199.1			197.6
BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.46		$	0.48		$	0.58		$	0.66
DILUTED EARNINGS PER AVERAGE COMMON SHARES ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.46		$	0.47		$	0.58		$	0.66
DIVIDENDS DECLARED PER COMMON SHARE	$	0.20875		$	0.19625		$	0.41750		$	0.39250

The accompanying Notes to CondensedConsolidatedFinancial 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)	2013			2012			2013			2012
Net income	$	93.0		$	101.6		$	121.0		$	149.1
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.8, $0.5, $1.2 and $0.9, respectively	1.0			0.7			1.9			1.5
Amortization of prior service cost, net of tax of $0.1, $0.1, $0.1 and $0.1, respectively	—			0.1			—			0.1
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.3, $0.3, $0.6 and $0.6, respectively	0.5			0.5			1.0			1.0
Amortization of prior service cost, net of tax of ($0.2), ($0.2), ($0.5) and ($0.5), respectively	(0.4		)	(0.4		)	(0.9		)	(0.9		)
Deferred commodity contracts hedging gains reclassified in net income, net of tax of $0, $0, ($0.1) and ($1.7), respectively	—			—			(0.1		)	(3.3		)
Deferred commodity contracts hedging losses, net of tax of $0, ($0.2), $0 and ($0.2), respectively	—			(0.3		)	—			(0.3		)
Amortization of deferred interest rate swap hedging losses, net of tax of $0, $0, $0.1 and $0.1, respectively	—			—			0.1			0.1
Other comprehensive income (loss), net of tax	1.1			0.6			2.0			(1.8		)
Comprehensive income (loss)	94.1			102.2			123.0			147.3
Less:  Comprehensive income attributable to noncontrolling interests	1.3			7.7			6.3			17.2
Less: Deconsolidation of Enogex Holdings	6.1			—			6.1			—
Total comprehensive income attributable to OGE Energy	$	86.7		$	94.5		$	110.6		$	130.1

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
(In millions)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	121.0		$	149.1
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	167.6			177.1
Impairment of assets	—			0.3
Deferred income taxes and investment tax credits, net	50.7			63.1
Equity in earnings of unconsolidated affiliates	(18.5		)	—
Allowance for equity funds used during construction	(2.7		)	(3.6		)
(Gain) loss on disposition and abandonment of assets	(8.7		)	0.7
Gain on insurance proceeds	—			(7.5		)
Stock-based compensation	(6.6		)	(9.4		)
Regulatory assets	3.7			10.3
Regulatory liabilities	(9.8		)	(7.6		)
Other assets	(0.6		)	4.8
Other liabilities	(24.2		)	(26.6		)
Change in certain current assets and liabilities
Accounts receivable, net	(41.4		)	19.9
Accrued unbilled revenues	(25.8		)	(25.3		)
Income taxes receivable	(3.5		)	(8.8		)
Fuel, materials and supplies inventories	(20.0		)	(3.6		)
Fuel clause under recoveries	(1.7		)	1.1
Other current assets	(7.4		)	(18.5		)
Accounts payable	(3.9		)	(92.6		)
Accounts payable - unconsolidated affiliates	10.5			—
Fuel clause over recoveries	(87.4		)	57.7
Other current liabilities	(11.4		)	0.9
Net Cash Provided from Operating Activities	79.9			281.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(565.0		)	(558.5		)
Investment in unconsolidated affiliates	(2.7		)	—
Proceeds from insurance	—			7.6
Reimbursement of capital expenditures	—			23.4
Proceeds from sale of assets	35.9			0.6
Net Cash Used in Investing Activities	(531.8		)	(526.9		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	247.5			—
Changes in advances with unconsolidated affiliates	126.2			—
Contributions from noncontrolling interest partners	107.0			1.0
Increase in short-term debt	47.8			319.6
Issuance of common stock	6.8			7.0
Payment of long-term debt	(0.1		)	—
Distributions to noncontrolling interest partners	(2.5		)	(8.0		)
Dividends paid on common stock	(82.6		)	(77.1		)
Net Cash Provided from Financing Activities	450.1			242.5
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1.8		)	(2.9		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1.8			4.6
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	1.7

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)	June 30, 2013 (Unaudited)		December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	1.8
Accounts receivable, less reserve of $1.5 and $2.6, respectively	186.7		295.3
Accounts receivable - unconsolidated affiliates	9.1		—
Accrued unbilled revenues	83.2		57.4
Income taxes receivable	10.7		7.2
Fuel inventories	98.7		93.3
Materials and supplies, at average cost	81.5		80.9
Deferred income taxes	97.7		187.7
Fuel clause under recoveries	1.7		—
Assets held for sale	—		25.5
Other	37.7		45.1
Total current assets	607.0		794.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,267.2		—
Other	55.9		52.2
Total other property and investments	1,323.1		52.2
PROPERTY, PLANT AND EQUIPMENT
In service	8,849.7		11,504.4
Construction work in progress	421.4		387.5
Total property, plant and equipment	9,271.1		11,891.9
Less accumulated depreciation	2,888.2		3,547.1
Net property, plant and equipment	6,382.9		8,344.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	501.9		510.6
Intangible assets, net	—		127.4
Goodwill	—		39.4
Other	33.6		53.6
Total deferred charges and other assets	535.5		731.0
TOTAL ASSETS	$	8,848.5	$	9,922.2

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

5

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS(Continued)

(In millions)	June 30, 2013 (Unaudited)			December 31, 2012
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	478.7		$	430.9
Accounts payable	219.6			396.7
Dividends payable	41.4			41.2
Customer deposits	69.7			70.3
Accrued taxes	40.3			48.1
Accrued interest	45.1			55.0
Accrued compensation	39.5			55.2
Fuel clause over recoveries	21.8			109.2
Other	60.5			69.8
Total current liabilities	1,016.6			1,276.4
LONG-TERM DEBT	2,400.2			2,848.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	366.9			399.8
Deferred income taxes	1,916.2			1,948.8
Deferred investment tax credits	2.9			3.9
Regulatory liabilities	244.4			245.1
Deferred revenues	0.2			37.7
Other	89.8			89.5
Total deferred credits and other liabilities	2,620.4			2,724.8
Total liabilities	6,037.2			6,849.8
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,059.7			1,047.4
Retained earnings	1,804.9			1,772.4
Accumulated other comprehensive loss, net of tax	(53.3		)	(49.1		)
Treasury stock, at cost	—			(3.5		)
Total OGE Energy stockholders' equity	2,811.3			2,767.2
Noncontrolling interests	—			305.2
Total stockholders' equity	2,811.3			3,072.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	8,848.5		$	9,922.2

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

6

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)

(In millions)	Common Stock		Premium on Common Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Treasury Stock			Total
Balance at December 31, 2012	$	1.0	$	1,046.4		$	1,772.4		$	(49.1	)	$	305.2		$	(3.5	)	$	3,072.4
Net income	—		—			114.8			—			6.2			—			121.0
Other comprehensive income (loss), net of tax	—		—			—			1.9			0.1			—			2.0
Dividends declared on common stock	—		—			(82.8		)	—			—			—			(82.8		)
Issuance of common stock	—		6.9			—			—			—			—			6.9
Stock-based compensation and other	—		(8.4		)	—			—			(0.8		)	3.5			(5.7		)
Contributions from noncontrolling interest partners	—		22.5			—			—			84.5			—			107.0
Distributions to noncontrolling interest partners	—		—			—			—			(2.5		)	—			(2.5		)
Deconsolidation of Enogex Holdings	—		—			0.5			(6.1		)	(392.7		)	—			(398.3		)
Deferred income taxes attributable to contributions from noncontrolling interest partners	—		(8.7		)	—			—			—			—			(8.7		)
2-for-1 forward stock split	1.0		(1.0		)	—			—			—			—			—
Balance at June 30, 2013	$	2.0	$	1,057.7		$	1,804.9		$	(53.3	)	$	—		$	—		$	2,811.3
Balance at December 31, 2011	$	1.0	$	1,034.3		$	1,574.8		$	(40.6	)	$	256.0		$	(6.2	)	$	2,819.3
Net income	—		—			131.0			—			18.1			—			149.1
Other comprehensive income (loss), net of tax	—		—			—			(0.9		)	(0.9		)	—			(1.8		)
Dividends declared on common stock	—		—			(77.4		)	—			—			—			(77.4		)
Issuance of common stock	—		7.0			—			—			—			—			7.0
Stock-based compensation and other	—		(14.1		)	—			—			(3.0		)	6.1			(11.0		)
Contributions from noncontrolling interest partners	—		—			—			—			1.0			—			1.0
Distributions to noncontrolling interest partners	—		—			—			—			(8.0		)	—			(8.0		)
Balance at June 30, 2012	$	1.0	$	1,027.2		$	1,628.4		$	(41.5	)	$	263.2		$	(0.1	)	$	2,878.2

The accompanying Notes to CondensedConsolidatedFinancial 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 two business segments:  (i) electric utility and (ii) natural gas midstream operations. For a discussion of the change in the Company’s business segments due to the formation of Enable Midstream Partners, see Note 12. For periods prior to May 1, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements. All significant intercompany transactions have been eliminated in consolidation.

Effective May 1, 2013,OGE Energy, the ArcLight group and CenterPoint Energy, Inc., formed Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPoint. In the formation transaction, OGE Energy and ArcLight contributed Enogex LLC to Enable Midstream Partners andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.The Company determined that its contribution of Enogex LLC to Enable Midstream Partners met the requirements of being in substance real estate and was recorded at historical cost.The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have50 percentof the management rights.Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energybegan accounting for its interest in Enable Midstream Partners using the equity method of accounting. Effective July 30, 2013, the name of Enogex Holdings was changed to Enable Intrastate Holdings II and the name of Enogex LLC was changed to Enable Oklahoma Intrastate Transmission, LLC.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations areconducted through OG&E and aresubject 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.

As discussed below, the Company completed a 2-for-1 stock split of the Company's common stock effective July 1, 2013. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

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 atJune 30, 2013andDecember 31, 2012, the results of its operations for the threeandsixmonths endedJune 30, 2013and2012and the results of its cash flows for thesixmonths endedJune 30, 2013and2012, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company'soperating results for the threeandsixmonths endedJune 30, 2013are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2013or 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 2012Form 10-K.

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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:

(In millions)	June 30, 2013		December 31, 2012
Regulatory Assets
Current
Crossroads wind farm rider under recovery (A)	$	11.3	$	14.9
Oklahoma demand program rider under recovery (A)	8.4		9.2
Fuel clause under recoveries	1.7		—
Other (A)	8.4		2.9
Total Current Regulatory Assets	$	29.8	$	27.0
Non-Current
Benefit obligations regulatory asset	$	357.0	$	370.6
Income taxes recoverable from customers, net	55.2		54.7
Smart Grid	43.4		42.8
Deferred storm expenses	17.2		12.7
Unamortized loss on reacquired debt	12.4		13.0
Deferred pension expenses	2.4		4.5
Other	14.3		12.3
Total Non-Current Regulatory Assets	$	501.9	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	21.8	$	109.2
Smart Grid rider over recovery (B)	19.4		24.1
Other (B)	5.1		7.8
Total Current Regulatory Liabilities	$	46.3	$	141.1
Non-Current
Accrued removal obligations, net	$	219.7	$	218.2
Pension tracker	12.6		9.2
Deferred pension credits	12.1		17.7
Total Non-Current Regulatory Liabilities	$	244.4	$	245.1

(A) Included in Other Current Assets on theCondensed Consolidated Balance Sheets.

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

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 OG&E 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, which could have significant financial effects.

Use of Estimates

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

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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 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 for all Company segments includes the determination of Pension Plan assumptions,impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas midstream operations segment, the most significant judgment is also exercised in the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill and equity method investments.

Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable Midstream Partners is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable Midstream Partners since it does not have the power to direct the activities of Enable Midstream Partners that are considered most significant to the economic performance of Enable Midstream Partners. As discussed above, OGE Energy accounts for the investment in Enable Midstream Partners using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income. OGE Energy's maximum exposure to loss related to Enable Midstream Partners is limited to OGE Energy's equity investment in Enable Midstream Partners as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2013. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during thesixmonths endedJune 30, 2013and2012.

	Six Months Ended
	June 30,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled (A)	(0.4		)	—
Accretion expense	1.1			0.9
Revisions in estimated cash flows (B)	—			26.7
Balance at June 30	$	54.7		$	52.4

(A) As a result of the formation of Enable Midstream Partners on May 1, 2013, the Company has no obligations at June 30, 2013 under OGE Holdings' asset retirement obligations previously disclosed in the Company's 2012 10-K.

(B) Due to changes to OG&E's asset retirement obligations related to its wind farms as a result of changes in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.

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Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to OGE Energy during the sixmonths endedJune 30, 2013. All amounts below are presented net of tax and noncontrolling interest.

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
	Net loss			Prior service cost		Net loss			Prior service cost			Deferred commodity contracts hedging gains			Deferred interest rate swap hedging losses			Noncontrolling interest			Total
Balance at December 31, 2012	$	(49.3	)	$	0.1	$	(15.7	)	$	7.2		$	0.1		$	(0.5	)	$	(9.0	)	$	(49.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9			—		1.0			(0.9		)	(0.1		)	0.1			0.1			1.9
Deconsolidation of Enogex Holdings	2.8			—		1.0			(0.3		)	(0.7		)	—			8.9			(6.1		)
Net current period other comprehensive income (loss)	4.7			—		2.0			(1.2		)	(0.8		)	0.1			9.0			(4.2		)
Balance at June 30, 2013	$	(44.6	)	$	0.1	$	(13.7	)	$	6.0		$	(0.7	)	$	(0.4	)	$	—		$	(53.3	)

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The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the three and sixmonths endedJune 30, 2013.

Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Gains (losses) on cash flow hedges
Commodity contracts	$	—		$	0.2		Cost of goods sold
Interest rate swap	—			(0.2		)	Interest expense
	$	—		$	—		Total before tax
Amortization of defined benefit pension items
Actuarial gains (losses)	$	(1.8	)	$	(3.1	)	(A)
Prior service cost	(0.1		)	(0.1		)	(A)
	(1.9		)	(3.2		)	Total before tax
	(0.9		)	(1.3		)	Tax benefit
	(1.0		)	(1.9		)	Net of tax
	—			(0.1		)	Noncontrolling interest
	$	(1.0	)	$	(1.8	)	Net of tax and noncontrolling interest
Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.8	)	$	(1.6	)	(A)
Prior service cost	0.6			1.4			(A)
	(0.2		)	(0.2		)	Total before tax
	(0.1		)	(0.1		)	Tax benefit
	$	(0.1	)	$	(0.1	)	Net of tax
Total reclassifications for the period	$	(1.1	)	$	(1.9	)	Net of tax and noncontrolling interest

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Forward Stock Split

On May 16, 2013, the Company's Board of Directors approved a 2-for-1 forward stock split of the Company's common stock, effective July 1, 2013, which entitled each shareholder of record to receive two shares for every one share of Company stock owned by the shareholder.  In connection with the stock split and as included as Exhibit 3.01 herein, an amendment to the Company's Articles of Incorporation was approved on May 16, 2013 which increased the number of authorized shares of common stock from225 millionto450 million. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Reclassifications

As discussed in Note 12, the formernatural gas transportation and storagesegment andnatural gas gathering and processingsegment have been combined into thenatural gas midstream operationssegment and have been restated for all prior periods presented.Effective May 1, 2013,the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.

As discussed above, as a result of the stock split effective July 1, 2013, all share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

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2. Accounting Pronouncement

In February 2013, the Emerging Issues Task Force issued "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward or Tax Credit Carryforward Exists." The new standard requires entities to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the statement of financial position as a reduction to a deferred tax asset for a net operating loss carryforward or a tax credit carryforward, except as follows. To the extent that a net operating loss carryforward or tax credit carryforward at the reporting date is not available under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, the unrecognized tax benefit would be presented in the statement of financial position as a liability. The new standard is applicable for all entities that have unrecognized tax benefits when a net operating loss carryforward or a tax credit carryforward exists. The new standard is effective for interim and annual reporting periods beginning after December 15, 2013 and does not require any new financial statement disclosures. This new standard may be applied retrospectively or prospectively with early adoption permitted. The Company retrospectively adopted this new standard effective January 1, 2013.

3. Investment in Unconsolidated Affiliates and Related Party Transactions

On March 14, 2013,OGE Energy entered into a Master Formation Agreement withthe ArcLight groupand CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight groupand CenterPoint Energy, Inc., agreed to form Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPointthat will initially be structured as a private limited partnership. This transaction closed on May 1, 2013.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributed100 percentof the equity interests inEnogex LLCto Enable Midstream Partners. Enogex LLC is a provider of integrated natural gas midstream services. Enogex LLC is engaged in the business of gathering, processing, transporting and storing natural gas.  Most of Enogex LLC's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. CenterPoint Energy Field Services, LLC, a Delaware limited liability company that provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States and wholly owned subsidiary of CenterPoint, was converted into a Delaware limited partnership that became Enable Midstream Partners. CenterPoint contributed to Enable Midstream Partners its equity interests in each of (i) CenterPoint Energy Gas Transmission Company, LLC, a Delaware limited liability company that is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas, (ii) MRT, a Delaware limited liability company that is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Illinois and Missouri and (iii) certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute a24.95 percentinterest in Southeast Supply Header, LLC, a Delaware limited liability company. CenterPoint indirectly owned a 50 percent interest in Southeast Supply Header, LLC, which owns a 1.0 billion cubic feet per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama.

Immediately prior to closing, on May 1, 2013, the ArcLight group contributed $107.0 million and OGE Energy contributed $9.1 million to Enogex LLC in order to pay down short-term debt. At June 30, 2013, OGE Energy holds 28.5 percent of the limited partners interests in Enable Midstream Partners.

CenterPoint has certain put rights, and Enable Midstream Partners has certain call rights, exercisable with respect to any interest in Southeast Supply Header, LLC retained by CenterPoint following the formation of Enable Midstream Partners, under which CenterPoint would contribute to Enable Midstream Partners CenterPoint's retained interest in Southeast Supply Header, LLC at a price equal to the fair market value of such interest at the time the put right or call right is exercised. If CenterPoint were to exercise such put right or Enable Midstream Partners were to exercise such call right, CenterPoint's retained interest in Southeast Supply Header, LLC would be contributed to Enable Midstream Partners in exchange for consideration consisting of a specified number of limited partnership units and, subject to certain restrictions, a cash payment, payable either from CenterPoint to Enable Midstream Partners or from Enable Midstream Partners to CenterPoint, in an amount such that the total consideration exchanged is equal in value to the fair market value of the contributed interest in Southeast Supply Header, LLC.

The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have50 percentof the management rights. CenterPoint and OGE Energy also own a 40 percent and 60 percent interest, respectively, in any incentive distribution rights to be held by the general partner of Enable Midstream Partners following an initial public offering of Enable Midstream Partners. In addition, for a period of time, the ArcLight group will have certain protective rights and approval rights over certain material activities of Enable Midstream Partners, including material increases in capital expenditures and certain equity issuances, entering into transactions with related parties and acquiring, pledging or disposing of

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certain material assets. The general partner of Enable Midstream Partners will initially be governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy, Inc. and OGE Energy. Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energydeconsolidated its interest in Enogex Holdings LLC andbegan accounting for its interest in Enable Midstream Partners using the equity method of accounting.

Pursuant to a Registration Rights Agreement dated as of May 1, 2013, OGE Energy and CenterPoint Energy, Inc. agreed to initiate the process for the sale of an equity interest in Enable Midstream Partners in an initial public offering. Enable Midstream Partners has agreed to file a registration statement for the initial public offering no later than May 1, 2014 and, subject to limited exceptions, consummate the initial public offering within 180 days of the filing of the registration statement. The Company currently expects that Enable Midstream Partners will file a registration statement during the fourth quarter of 2013. The initial public offering is subject to market conditions and OGE Energy can give no assurances that the initial public offering will be consummated.

Effective May 1, 2013, Enable Midstream Partnersentered into a$1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's$400 millionrevolving credit facility was terminated.

Subject to the exceptions provided below, pursuant to the terms of an Omnibus Agreement dated as of May 1, 2013 among OGE Energy, the ArcLight group and CenterPoint Energy, Inc., each of OGE Energy and CenterPoint Energy, Inc. will be required to hold or otherwise conduct all of its respective Midstream Operations (as defined below) located within the United States in Enable Midstream Partners. This restriction will cease to apply to both OGE Energy and CenterPoint Energy, Inc. as soon as either OGE Energy or CenterPoint Energy, Inc. ceases to hold (i) any interest in the general partner of Enable Midstream Partners or (ii) at least 20 percent of the limited partner interests of Enable Midstream Partners. "Midstream Operations" generally means, subject to certain exceptions, the gathering, compression, treatment, processing, blending, transportation, storage, isomerization and fractionation of crude oil and natural gas, its associated production water and enhanced recovery materials such as carbon dioxide, and its respective constituents and the following products: methane, NGLs (Y-grade, ethane, propane, normal butane, isobutane and natural gasoline), condensate, and refined products and distillates (gasoline, refined product blendstocks, olefins, naphtha, aviation fuels, diesel, heating oil, kerosene, jet fuels, fuel oil, residual fuel oil, heavy oil, bunker fuel, cokes, and asphalts), to the extent such activities are located within the United States.

In addition, if OGE Energy or CenterPoint Energy, Inc. acquires any assets or equity of any person engaged in Midstream Operations with a value in excess of $50 million (or $100 million in the aggregate with such party's other acquired Midstream Operations that have not been offered to Enable Midstream Partners), the acquiring party will be required to offer Enable Midstream Partners the opportunity to acquire such assets or equity for such value; provided, that the acquiring party will not be obligated to offer any such assets or equity to Enable Midstream Partners if the acquiring party intends to cease using them in Midstream Operations within 12 months. If Enable Midstream Partners does not exercise its option, then the acquiring party will be free to retain and operate such Midstream Operations; provided, however, that if the fair market value of such Midstream Operations is greater than 66 2/3 percent of the fair market value of all of the assets being acquired in such transaction, then the acquiring party will be required to dispose of such Midstream Operations within 24 months.

As long as the ArcLight group has certain protective rights, the ArcLight group will be prohibited from pursuing any transaction independently from Enable Midstream Partners (i) if the ArcLight group's consent is required for Enable Midstream Partners to pursue such transaction and (ii) the ArcLight group affirmatively votes not to consent to such transaction.

On May 1, 2013, OGE Energy, OGE Holdings and Enable Midstream Partners entered into a Seconding Agreement. During the term of the Seconding Agreement, OGE Holdings' employees will continue to perform services for Enable Midstream Partners and its subsidiaries.

Related Party Transactions

As OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013, operating costs charged between the Company and its affiliate, Enable Midstream Partners, after May 1, 2013, which were previously eliminated in consolidation, are discussed below.

OGE Energy charged operating costs to the Enogex Holdings/Enable Midstream Partners of$7.9 million and $14.6 millionduring thethree and sixmonths endedJune 30, 2013, respectively. OGE Energy charges operating costs to its subsidiaries and unconsolidated affiliates based on several factors. Operating costs directly related to specific subsidiaries and unconsolidated affiliates are assigned to those subsidiaries and unconsolidated affiliates.  Where more than one subsidiary or unconsolidated affiliate benefits from certain expenditures, the costs are shared between those subsidiaries and unconsolidated affiliates receiving

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the benefits.  Operating costs incurred for the benefit of all subsidiaries and unconsolidated affiliates are allocated among the subsidiaries and unconsolidated affiliates, either as overhead based primarily on labor costs or using the "Distrigas" method.  The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.  OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff.  OGE Energy believes this method provides a reasonable basis for allocating common expenses.

As OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013, related party transactions between the Company and its affiliate, Enable Midstream Partners, after May 1, 2013, which were previously eliminated in consolidation, are discussed below.

	Two Months Ended
	June 30,
(In millions)	2013
Operating Revenues:
Electricity to power electric compression assets	$	1.3
Cost of Goods Sold:
Natural gas transportation services	$	5.8
Natural gas storage services	2.3
Natural gas purchases (A)	2.5

(A) AtJune 30, 2013, there was $1.2 millionof natural gas purchases recorded for these activities.

Summarized Financial Information of Enable Midstream Partners

As Enable Midstream Partners began operations on May 1, 2013, summarized unaudited financial information for 100 percent of Enable Midstream Partners is presented below at June 30, 2013 (at historical cost) and for the two months ended June 30, 2013. Fair value information for Enable Midstream Partners' information below is not currently available; however, OGE Holdings expects these fair value amounts to be available by the end of the third quarter of 2013.

Balance Sheet	June 30, 2013
	(In millions)
Current assets	$	393.9
Non-Current assets	8,209.2
Current liabilities	379.6
Non-Current liabilities	2,249.1

	Two Months Ended
Income Statement	June 30, 2013
	(In millions)
Operating revenues	$	502.0
Gross margin	207.4
Operating expenses	132.4
Net income	65.1

Enable Midstream Partners concluded that the formation of Enable Midstream Partners was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes.  Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex Holdings' assets, liabilities and equity will accordingly be adjusted to estimated fair value as of May 1, 2013.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  Enable Midstream Partners is using appraisers to assist in the determination of fair value of certain assets.  Enable Midstream Partners' valuation is expected to be finalized in the third quarter of 2013.  OGE Energy does not expect that its estimated equity in earnings of Enable Midstream Partners in the second quarter of 2013 will be materially different as a result of the fair value determination.

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4. Fair Value Measurements

The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is 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 options 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).

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, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets 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.

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The Company hadnomaterial financial instruments measured at fair value on a recurring basis atJune 30, 2013. The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012 as well as presents the Company's commodity contracts fair value included in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company adopted the Financial Accounting Standards Board accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company posted $0.2 million of collateral at December 31, 2012 which has been included within netting adjustments in the table below. The Company held no collateral at December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company held no Level 3 investments at December 31, 2012.

December 31, 2012
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	5.0		$	5.0		$	—	$	—
Significant other observable inputs (Level 2)	0.5			0.5			3.1		3.8
Total fair value	5.5			5.5			3.1		3.8
Netting adjustments	(5.0		)	(5.2		)	—		—
Total	$	0.5		$	0.3		$	3.1	$	3.8

(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 assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012, 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.

(C) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million at December 31, 2012, 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 fair value and carrying amount of the Company's financial instruments at June 30, 2013 and December 31, 2012.

	June 30, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,154.3	$	2,465.6	$	1,904.2	$	2,401.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.6		10.7		10.7		10.0
OGE Energy Senior Notes	99.9		104.5		99.9		106.3
Enogex LLC Senior Notes	(A)		(A)		448.4		493.4
Enogex LLC Term Loan	(A)		(A)		250.0		250.0

(A) As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company's consolidated financial statements do not include any obligations for the Enogex LLC Senior Notes and Enogex LLC Term Loan as of May 1, 2013.

The Company's long-term debt is valued at the carrying amount.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 and is classified as Level 2 in the fair value hierarchy except for the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

5. Derivative Instruments and Hedging Activities

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

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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 (Loss) 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 previously designated as cash flow hedges derivatives for OGE Holdings' 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 operations and natural gas transportation and storage operations (operational gas hedges).  The Company also previously designated as cash flow hedges certain derivatives for certain natural gas storage inventory positions. The Company had no material instruments designated as cash flow hedges at June 30, 2013.

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, 2013 and December 31, 2012, 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 OGE Holdings' asset management activities.  For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

At June 30, 2013 and December 31, 2012, the Company had no material derivative instruments that were not designated as hedging instruments.

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Balance Sheet Presentation Related to Derivative Instruments

The Company had no material derivative instruments included in its Condensed Consolidated Balance Sheet at June 30, 2013. The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2012 are as follows:

		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	—	$	0.5
Total		$	—	$	0.5
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.1	$	—
	Other Current Assets	5.0		4.7
Physical Purchases/Sales	Current PRM	0.4		0.3
Total		$	5.5	$	5.0
Total Gross Derivatives (A)		$	5.5	$	5.5

(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, 2012.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for thethreemonths endedJune 30, 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.5	)	$	—		$	—
Interest Rate Swap	—			(0.1		)	—
Total	$	(0.5	)	$	(0.1	)	$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(3.7	)
Natural Gas Financial Futures/Swaps	0.6
Total	$	(3.1	)

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The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for thesixmonths endedJune 30, 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.2	)	$	5.2		$	—
Interest Rate Swap	—			(0.2		)	—
Total	$	(0.2	)	$	5.0		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(6.1	)
Natural Gas Financial Futures/Swaps	1.0
Total	$	(5.1	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income (Loss) into income (effective portion) and amounts recognized in income (ineffective portion) for the threeandsixmonths endedJune 30, 2012, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the threeandsixmonths endedJune 30, 2012, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

At June 30, 2013 the Company had no derivative instruments that contain credit-risk related contingent features.

6. Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethreeandsixmonths endedJune 30, 2013 and 2012related to the Company's performance units and restricted stock.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Performance units
Total shareholder return	$	1.9	$	2.0	$	3.9	$	3.8
Earnings per share	0.7		0.6		1.3		1.3
Total performance units	2.6		2.6		5.2		5.1
Restricted stock	0.1		0.2		0.2		0.4
Total compensation expense	2.7		2.8		5.4		5.5
Less: Amount paid by unconsolidated affiliates	0.6		—		0.6		—
Net compensation expense	$	2.1	$	2.8	$	4.8	$	5.5
Income tax benefit	$	1.0	$	1.1	$	2.1	$	2.2

The Company has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During thethreeandsixmonths endedJune 30, 2013, there were33,000shares and549,520shares, respectively, of newcommon stock issuedpursuant to the Company's stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. During the sixmonths endedJune 30, 2013, there were 125,264 of treasury stock shares issued. During thethreeandsixmonths endedJune 30, 2013, there were5,810sharesand6,474sharesof restricted stock, respectively, returned to the Company to satisfy tax liabilities. The Company received $1.2 million and $1.4 million during the threeandsixmonths endedJune 30, 2013 related to exercised stock options. The Company did not realize an

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income tax benefit for the tax deductions from the exercised stock options during the threeandsixmonths endedJune 30, 2013 due to the Company being in a tax net operating loss position in 2013.

As a result of the formation of Enable Midstream Partners on May 1, 2013, 50 percent of OGE Holdings' 2013 performance unit grants that were previously based on earnings before interest, taxes, depreciation and amortization were converted to stock-based compensation. The performance unit grants converted totaled 91,390, which is comprised of 45,596 total shareholder return performance units with a $25.89 grant date fair value and 45,794 earnings per share performance units with a $26.73 grant date fair value. The amount of these performance units were adjusted for the effects of the stock split.

7. 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 to2009or state and local tax examinations by tax authorities for years prior to2005.  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.OG&E 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 production from its wind farmsand earnsOklahoma state tax credits associated withitsinvestments in electric generatingfacilities which further reduce the Company's effective tax rate.

As previously reported in the Company's 2012 Form 10-K, in January 2013, OG&E determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During the first quarter of 2013, OG&E recorded a reserve of$7.8 million ($5.1 millionafter tax) related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized due to management's determination that it is more likely than not that it will be unable to utilize these credits.

As a result of acquiring an equity interest in Enable Midstream Partners, the Company has a lower effective tax rate in conjunction with the formation of Enable Midstream Partners in states with lower state tax rates, which reduced income tax expense for the three months ended June 30, 2013 by $3.9 million. In addition, deferred tax adjustments related to the Company's deconsolidation of Enogex Holdings increased income tax expense for the three months ended June 30, 2013 by $3.9 million.

Acquisition of the equity interest in Enable Midstream Partners on May 1, 2013, is also expected to increase the Company's utilization of net operating loss carryforwards throughout 2013. The Company now projects utilization of approximately $227.0 million ($147.6 million after tax) of Federal net operating loss carryforwards and $42.0 million ($39.6 million after tax) of state net operating loss carryforwards in 2013.

8. Common Equity

Forward Stock Split

On May 16, 2013, the Company's Board of Directors approved a 2-for-1 forward stock split of the Company's common stock, effective July 1, 2013, which entitled each shareholder of record to receive two shares for every one share of Company stock owned by the shareholder.  In connection with the stock split and as included as Exhibit 3.01 herein, an amendment to the Company's Articles of Incorporation was approved on May 16, 2013 which increased the number of authorized shares of common stock from225 millionto450 million. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 91,588 shares and 198,790 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and sixmonths endedJune 30, 2013 and received proceeds of $3.3 million and $6.4 million, respectively.  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, 2013, there were 4,046,198 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

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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)	2013		2012		2013		2012
Net Income Attributable to OGE Energy	$	91.7	$	93.9	$	114.8	$	131.0
Average Common Shares Outstanding
Basic average common shares outstanding	198.3		197.2		198.0		196.8
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.1		0.6		1.1		0.8
Diluted average common shares outstanding	199.4		197.8		199.1		197.6
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.46	$	0.48	$	0.58	$	0.66
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.46	$	0.47	$	0.58	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

9. Long-Term Debt

AtJune 30, 2013, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day.  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)
0.20%	-	0.34%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.21%	-	0.39%	Muskogee Industrial Authority, January 1, 2025	32.4
0.15%	-	0.30%	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, at100 percentof 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.

Issuance of New Long-Term Debt

On May 8, 2013, OG&E issued$250 millionof3.9%senior notes dueMay 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures, general corporate expenses

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and for working capital purposes. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.

10. Short-Term Debt and CreditFacilities

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$478.7 millionand$430.9 millionatJune 30, 2013andDecember 31, 2012, respectively. The following table provides information regarding the Company's revolving credit agreements at June 30, 2013.

	Aggregate			Amount		Weighted-Average
Entity	Commitment			Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0		$	478.7	0.31	%	(E)	December 13, 2017	(F)
OG&E (C)	400.0			2.1		0.53	%	(E)	December 13, 2017	(F)
Total	$	1,150.0	(D)	$	480.8	0.31	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2013.

(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, 2013, there was $478.7 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, 2013, there was $2.1 million supporting letters of credit.

(D) Effective May 1, 2013, Enable Midstream Partnersentered into a$1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's$400 millionrevolving credit facility was terminated.

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

(F) In December 2011,the Company andOG&E entered intounsecured five-year revolving credit agreements to total in the aggregate1,150.0 million ($750 millionfor the Company and$400 millionfor OG&E).Each of thecredit facilitiescontainan option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013,the Company andOG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity oftheircredit agreementsto December 13, 2017.

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 downgradecould 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 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2013 and ending December 31, 2014.

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11. 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												Restoration of Retirement Income Plan
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)			2013 (B)		2012 (B)		2013 (C)		2012 (C)
Service cost	$	4.5		$	4.5		$	9.5		$	9.0		$	0.3	$	0.2	$	0.6	$	0.5
Interest cost	6.8			7.5			13.4			15.0			0.2		0.2		0.3		0.3
Expected return on plan assets	(11.9		)	(11.5		)	(24.2		)	(23.0		)	—		—		—		—
Amortization of net loss	7.0			6.0			13.2			11.9			0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost (A)	0.4			0.5			0.9			1.1			—		0.1		0.1		0.3
Total net periodic benefit cost	6.8			7.0			12.8			14.0			0.6		0.6		1.2		1.3
Less: Amount paid by unconsolidated affiliates	1.0			—			1.0			—			—		—		—		—
Net periodic benefit cost (net of unconsolidated affiliates)	$	5.8		$	7.0		$	11.8		$	14.0		$	0.6	$	0.6	$	1.2	$	1.3

(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B) In addition to the$6.4 millionand$7.6 millionof net periodic benefit cost recognizedduring thethreemonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in pension expense during thethreemonths endedJune 30, 2013and2012of$1.2 millionand$2.8 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$13.0 millionand$15.3 millionof net periodic benefit cost recognizedduring thesixmonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in pension expense during thesixmonths endedJune 30, 2013and2012of$3.1 millionand$5.7 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)
Service cost	$	1.0		$	1.1		$	2.2		$	2.1
Interest cost	2.6			3.0			5.2			6.0
Expected return on plan assets	(0.7		)	(0.7		)	(1.3		)	(1.5		)
Amortization of transition obligation	—			0.7			—			1.4
Amortization of net loss	5.4			5.1			10.7			10.2
Amortization of unrecognized prior service cost (A)	(4.2		)	(4.2		)	(8.3		)	(8.3		)
Total net periodic benefit cost	4.1			5.0			8.5			9.9
Less: Amount paid by unconsolidated affiliates	0.4			—			0.4			—
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.7		$	5.0		$	8.1		$	9.9

(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B) In addition to the$3.7 millionand$5.0 millionof net periodic benefit cost recognizedduring thethreemonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthethreemonths endedJune 30, 2013and2012of$0.2 millionand$0.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

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(C) In addition to the$8.1 millionand$9.9 millionof net periodic benefit cost recognizedduring thesixmonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthesixmonths endedJune 30, 2013and2012of$0.3 millionand$0.8 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

The capitalized portion of net periodic pension benefit cost was $1.5 million and $2.6 million during the three and sixmonths endedJune 30, 2013 as compared to $1.6 million and $3.1 million during the same period in 2012. The capitalized portion of net periodic postretirement benefit cost was $0.8 million and $1.6 million during the three and sixmonths endedJune 30, 2013 as compared to $1.0 million and $2.0 million during the same period in 2012.

Pension Plan Funding

The Companypreviously reported in its 2012 Form 10-K that it may contribute up to$35 millionto its Pension Plan during 2013. In May 2013,the Companycontributed$35 millionto its Pension Plan. No additional contributions are expected in 2013.

12. Report of Business Segments

Previously, the Company's business was divided into three segmentsas follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing. On March 14, 2013,OGE Energy entered into a Master Formation Agreement withthe ArcLight groupand CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight groupand CenterPoint Energy, Inc., agreed to form Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPointthat will initially be structured as a private limited partnership. As a result, effective May 1, 2013, OGE Energydeconsolidated its interest in Enogex Holdings LLC andbegan accounting for its interest in Enable Midstream Partners using the equity method of accounting. The Company's business is now divided into two segments for financial reporting purposes as follows: (i) electric utility and (ii) natural gas midstream operations. The formernatural gas transportation and storagesegment andnatural gas gathering and processingsegment have been combined into thenatural gas midstream operationssegment and have been restated for all prior periods presented. Equity in earnings of unconsolidated affiliates in the natural gas midstream operations segment includes OGE Energy's equity interest in Enable Midstream Partners from May 1, 2013 through June 30, 2013. Other than equity in earnings of unconsolidated affiliates, all amounts for the natural gas midstream operations segment are through April 30, 2013. Investment in unconsolidated affiliates in the natural gas midstream operations segment includes OGE Energy's investment in Enable Midstream Partners at June 30, 2013. 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 during the threemonths endedJune 30, 2013 and 2012.

Three Months Ended June 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	574.6	$	166.1	$	—		$	(6.5	)	$	734.2
Cost of goods sold	247.6		129.7		—			(6.7		)	370.6
Gross margin on revenues	327.0		36.4		—			0.2			363.6
Other operation and maintenance	107.0		15.7		(0.7		)	—			122.0
Depreciation and amortization	62.0		9.2		3.2			—			74.4
Taxes other than income	19.9		2.5		0.9			—			23.3
Operating income (loss)	$	138.1	$	9.0	$	(3.4	)	$	0.2		$	143.9
Equity in earnings of unconsolidated affiliates	$	—	$	18.5	$	—		$	—		$	18.5
Investment in unconsolidated affiliates	$	—	$	1,267.2	$	—		$	—		$	1,267.2
Total assets	$	7,453.6	$	1,266.8	$	189.4		$	(61.3	)	$	8,848.5

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Three Months Ended June 30, 2012	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	528.0	$	344.0	$	—		$	(17.0	)	$	855.0
Cost of goods sold	204.6		222.6		—			(17.9		)	409.3
Gross margin on revenues	323.4		121.4		—			0.9			445.7
Other operation and maintenance	114.7		42.7		(4.4		)	—			153.0
Depreciation and amortization	62.7		24.3		3.5			—			90.5
Impairment of assets	—		0.1		—			—			0.1
Taxes other than income	18.2		5.7		0.9			—			24.8
Operating income (loss)	$	127.8	$	48.6	$	—		$	0.9		$	177.3
Total assets	$	6,833.2	$	2,395.3	$	331.4		$	(208.5	)	$	9,351.4

Six Months Ended June 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.1	$	630.4	$	—		$	(24.9	)	$	1,635.6
Cost of goods sold	460.6		489.0		—			(26.0		)	923.6
Gross margin on revenues	569.5		141.4		—			1.1			712.0
Other operation and maintenance	212.1		60.9		(3.0		)	—			270.0
Depreciation and amortization	123.3		36.8		6.2			—			166.3
Taxes other than income	43.1		10.5		2.8			—			56.4
Operating income (loss)	$	191.0	$	33.2	$	(6.0	)	$	1.1		$	219.3
Equity in earnings of unconsolidated affiliates	$	—	$	18.5	$	—		$	—		$	18.5
Investment in unconsolidated affiliates	$	—	$	1,267.2	$	—		$	—		$	1,267.2
Total assets	$	7,453.6	$	1,266.8	$	189.4		$	(61.3	)	$	8,848.5

Six Months Ended June 30, 2012	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	954.7	$	773.6		$	—		$	(32.6	)	$	1,695.7
Cost of goods sold	400.1		527.9			—			(33.4		)	894.6
Gross margin on revenues	554.6		245.7			—			0.8			801.1
Other operation and maintenance	225.3		85.0			(9.7		)	—			300.6
Depreciation and amortization	122.4		47.7			7.0			—			177.1
Impairment of assets	—		0.3			—			—			0.3
Gain on insurance proceeds	—		(7.5		)	—			—			(7.5		)
Taxes other than income	39.3		13.0			2.7			—			55.0
Operating income (loss)	$	167.6	$	107.2		$	—		$	0.8		$	275.6
Total assets	$	6,833.2	$	2,395.3		$	331.4		$	(208.5	)	$	9,351.4

13. Commitments and Contingencies

Except as set forth below and in Note 14, the circumstances set forth in Notes 16 and 17 to the Company's Consolidated Financial Statements included in the Company's 2012Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

OG&E Minimum Fuel Purchase Commitments

OG&E has coal contracts for purchases from January 2012 through December 2016. Also, as previously reported, OG&E had entered into multiple month term natural gas contracts for26.1 percentof its 2013 annual forecasted natural gas requirements.

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In February 2013, through a request for proposal, OG&E entered into various multiple month term natural gas contracts for55.8 percentof its remaining forecasted 2013 natural gas requirements.Additional gas supplies to fulfill OG&E's remaining 2013 natural gas requirements will be acquired through monthly and daily purchases which are expected to be made at market prices.

OG&E Long-Term Service Agreement Commitments

OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant.  The existing contract will expire on January 1, 2015. In May 2013, a new contract was signed that is expected to run for the earlier of128,000factored-fired hours or3,600factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.

OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional24,000factored-fired hours. Based on historical usage and current expectations for future usage, this contract is expected to run until 2027. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

Enable Midstream Partners Transportation Contract

Enable Midstream Partners provides gas transmission delivery services to all of PSO's natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. The PSO contract provides for a monthly demand charge plus variable transportation charges including fuel. The stated term of the PSO contract was set to expire January 1, 2014, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period.  Because neither party provided notice of termination 180 days prior to January 1, 2014, the PSO contract will remain in effect at least through January 1, 2015.

OGE Holdings Noncancellable Operating Leases

As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company has no obligations included in its Consolidated Financial Statements at June 30, 2013 under OGE Holdings' noncancellable lease obligations previously disclosed in the Company's 2012 Form 10-K.

Enogex Energy Resources, Inc. Commitments

As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company has no obligations included in its Consolidated Financial Statements at June 30, 2013, under Enogex Energy Resources, Inc.'s commitments previously disclosed in the Company's 2012 Form 10-K.

Environmental Laws and Regulations

United States v. OG&E (Federal Clean Air Act New Source Review Litigation)

As previously reported, in July 2008, OG&E 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. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects 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.

In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with the EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. OG&E expects to vigorously defend against these

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claims, but OG&E cannot predict the outcome of such litigation. The Sierra Club, an environmental organization, also has threatened to file a citizen suit under the Federal Clean Air Act alleging similar violations against OG&E, and OG&E expects that the Sierra Club will seek to intervene in the litigation initiated by the EPA. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act.

If OG&E does not prevail and if a new assessment of the projects were to conclude that they caused a significant emissions increase, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including Dry Scrubbers and selective catalytic reduction systems with capital costs in excess of$1.0 billionand pay fines and significant 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$37,500per day for each violation. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs.

Other

In the normal course of business,the Companyis confronted with issues or events that may result in a contingent liability.These generally relate to lawsuits or claims made by third parties, including governmental agencies.When appropriate, management consults with legal counsel and other appropriate experts to assess the claim.If, in management's opinion,the Companyhas 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.At the present time, based on currently available information, except as otherwise stated above, in Note 14 below, under "Environmental Laws and Regulations" in Item 2 of Part 1 and in Item 1 of Part II of this Form 10-Q, in Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I of the Company's 2012Form 10-K, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

14. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 17 to the Company's Consolidated Financial Statements included in the Company's 2012Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Crossroads Wind Farm

As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 megawatts. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On April 15, 2013, the APSC issued an order authorizing OG&E to recover the Arkansas portion of the cost to construct the Crossroads wind farm, effective retroactively to August 1, 2012. The costs will be recovered through the Energy Cost Recovery Rider.

Market-Based Rate Authority

On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order accepting OG&E's June 2012 triennial market power update.

Fuel Adjustment Clause Review for Calendar Year 2011

On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. On April 9, 2013, the OCC administrative law judge recommended that the OCC find

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that for the calendar year 2011 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. On June 18, 2013, the OCC issued an order approving the administrative law judge’s recommendation.

Pending Regulatory Matters

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. 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.

Order No. 1000 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, Order No. 1000 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, Order No. 1000 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. Order No. 1000 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. These changes to the "right of first refusal" 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 were filed on November 13, 2012. On May 29, 2013, the Governor signed House Bill 1932 into law which establishes a right of first refusal for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts that interconnect to those incumbent entities' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000.

On July 18, 2013, the FERC issued an order on the SPP's Order No. 1000 compliance filing.  This order accepted in part and rejected in part the SPP's plan for complying with Order No. 1000.  The FERC rejected the SPP's plan to retain the right of first refusal for projects that would operate between 100 kilovolts and 300 kilovolts.  However, the FERC clarified that a right of first refusal was appropriate in certain circumstances.  It is not clear how the FERC's order will relate to the recently enacted Oklahoma law addressing a right of first refusal for lower voltages.  The SPP was ordered to submit another compliance filing by November 15, 2013.

OGE Energy cannot, at this time, determine the precise impactof Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, OGE Energy 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.

Fuel Adjustment Clause Review for Calendar Year 2012

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2013, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs.

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 two business

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segments:  (i) electric utility and (ii) natural gas midstream operations. For a discussion of the change in the Company’s business segments due to the formation of Enable Midstream Partners, see Note 12 of Notes to Condensed Consolidated Financial Statements. For periods prior to May 1, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements.

Effective May 1, 2013,OGE Energy, the ArcLight group and CenterPoint Energy, Inc., formed Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPoint. In the formation transaction, OGE Energy and ArcLight contributed Enogex LLC to Enable Midstream Partners andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.The Company determined that its contribution of Enogex LLC to Enable Midstream Partners met the requirements of being in substance real estate and was recorded at historical cost.The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have50 percentof the management rights.Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energybegan accounting for its interest in Enable Midstream Partners using the equity method of accounting.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations areconducted through OG&E and aresubject 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.

As discussed in Note 1 of Notes to Condensed Consolidated Financial Statements, the Company completed a 2-for-1 stock split of the Company's common stock effective July 1, 2013. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Overview

Company Strategy

The Company'smission is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure, through its equity interest in Enable Midstream Partners, and meet individual customers' needs for energy and related services focusing on safety, efficiency, reliability, customer service and risk management.The Company'scorporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and unregulated natural gas midstream business, through its equity interest in Enable Midstream Partners, while providing competitive energy products and services to customers primarily in the south central United States as well as seeking growth opportunities in both businesses.Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders.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 increasing the dividend to meet the Company's dividend payout objectives.  The Company's target payout ratio is to pay out 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

ThreeMonths EndedJune 30, 2013as Compared toThreeMonths EndedJune 30, 2012

Net income attributable to OGE Energy was$91.7 million, or$0.46per diluted share,during thethreemonths endedJune 30, 2013as compared to$93.9 million, or$0.47per diluted share,during the same period in2012. Thedecreasein net income attributable to OGE Energy of$2.2 million, or2.3 percent, during thethreemonths endedJune 30, 2013as compared to the same period in2012was primarily due to:

• an increasein net income at OG&E of$5.6 million, or7.6 percent, or$0.03per diluted share of the Company's common stock, primarily due to a higher gross margin mainly attributable to higher transmission revenue partially offset by milder weather, and lower other operations and maintenance expense. These increases in net income were partially offset by higher taxes other than income, higher interest expense and higher income tax expense;

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• a decreasein net income attributable to OGE Holdings of$6.2 million, or29.5 percent, or$0.03per diluted shareof the Company's common stock, due to lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex LLC's five largest customers from keep-whole to fixed-fee, in addition to slightly higher other operation and maintenance expense and depreciation and amortization expense.These decreases were partially offset bythe accretive effect to OGE Holdings of Enable Midstream Partners,increased gathering rates and volumes and inlet processing volumes associated with ongoing expansion projects and the gas gathering assets acquired in August 2012; and

• a decreasein net income attributable to OGE Energy of$1.6 million, or$0.01per diluted shareof the Company's common stock, primarily due to transaction expenses related to the formation of Enable Midstream Partners as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

SixMonths EndedJune 30, 2013as Compared toSixMonths EndedJune 30, 2012

Net income attributable to OGE Energy was$114.8 million, or$0.58per diluted share,during thesixmonths endedJune 30, 2013as compared to$131.0 million, or$0.66per diluted share,during the same period in2012. Thedecreasein net income attributable to OGE Energy of$16.2 million, or12.4 percent, during thesixmonths endedJune 30, 2013as compared to the same period in2012was primarily due to:

• an increasein net income at OG&E of$6.5 million, or7.6 percent, or$0.03per diluted share of the Company's common stock, primarily due to a higher gross margin mainly attributable to higher transmission revenue partially offset by lower recovery of investments, and lower other operation and maintenance expense. These increases in net income were partially offset by higher taxes other than income, lower other income, higher interest expense and higher income tax expense;

• a decreasein net income attributable to OGE Holdings of$18.8 million, or41.0 percent, or$0.09per diluted shareof the Company's common stock, due to lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex LLC's five largest customers from keep-whole to fixed-fee, in addition to slightly higher other operation and maintenance expense and depreciation and amortization expense.These decreases were partially offset bythe accretive effect to OGE Holdings of Enable Midstream Partners,increased gathering rates and volumes and inlet processing volumes associated with ongoing expansion projects and the gas gathering assets acquired in August 2012; and

• a decreasein net income attributable to OGE Energy of$3.9 million, or$0.02per diluted shareof the Company's common stock, primarily due to losses associated with valuation differences between the deferred compensation assets and liabilities for investments that are based on the Company's common stock and transaction expenses related to the formation of Enable Midstream Partners as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

Regulatory Matter

Enable Midstream Partners FERC Rate Proceeding

In August 2012, MRT, a subsidiary of Enable Midstream Partners and an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Illinois and Missouri, made a rate filing with the FERC pursuant to Section 4 of the Natural Gas Act. In its filing, MRT requested an annual cost of service of $103.8 million (an increase of approximately $47.3 million above the annual cost of service underlying the current FERC approved maximum rates for MRT's pipeline), new depreciation rates, an overall rate of return of 10.813 percent (based on a return on equity of 13.62 percent), a regulatory compliance cost surcharge with a true-up mechanism to recover safety, environmental, and security costs associated with mandated requirements and billing determinants reflecting no adjustments for MRT's conversion of a portion of CenterPoint Energy Gas Transmission Company, LLC's firm capacity to a lease. In August 2012, a number of parties filed protests in response to MRT's rate filing. In September 2012, the FERC issued an order accepting MRT's filing, suspending the filed tariff rates for the full statutorily permitted five month suspension period and setting certain issues for hearing. Following continued negotiations with its customers, on July 25, 2013, MRT filed a motion to suspend the procedural schedule for the proceeding, which motion was granted on July 26, 2013.  On July 30, 2013, MRT filed with the FERC an uncontested Stipulation and Agreement and Offer of Settlement, resolving all issues in the rate case.  In particular, MRT withdrew its proposed regulatory compliance cost surcharge.  The settlement specifies few particulars, other than setting an annual overall cost-of-service for MRT of $84.0 million and increasing the depreciation rates for certain asset classes.  MRT expects the FERC approval of the settlement either late in the third quarter or early in the fourth quarter of 2013, with the settlement rates going into effect thereafter.  MRT will be making refunds to certain of its customers for amounts collected between the requested $103.8 million cost of service and the $84.0 million settlement cost of service, which amounts have already been reserved by Enable Midstream Partners.

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2013 Outlook

The Company's2013consolidatedearnings guidanceremains unchanged betweenapproximately $335 million to $360 million of net income, or$1.68 to $1.80 per average diluted share(adjusted for the stock split). However, the Company is projecting earnings to be at the high end of the guidance range based primarily on the accretive impact of the formation of Enable Midstream Partners,partially offset by higher transaction costs associated with the agreement at the holding company. This guidanceassumes normal weather for the remainder of the yearand includes the impact from OGE Energy's equity interest in Enable Midstream Partners as well as certain assumptions discussed below. See the Company's 2012Form 10-K for other key factors and assumptions underlying its 2013 earnings guidance.

Key assumptions for 2013 include:

Consolidated OGE

• Approximately 200 million average diluted shares outstanding (adjusted for the stock split); and

• A projected loss at the holding company between approximately $6 million and $8 million, or $0.03 to $0.04 per diluted share, as compared to previous earnings guidance of between approximately $2 million and $4 million, or $0.01 to $0.02 per diluted share, primarily due to transaction expenses related to the formation of Enable Midstream Partners as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

Natural Gas Midstream Operations

The Company projects earnings from Natural Gas Midstream Operations to be between $70 million and $90 million of net income or $0.35 to $0.45 per average diluted share, an increase from the previously issued guidance of between approximately $55 million to $75 million, or $0.28 to $0.38 per average diluted share. The increase is based primarily on the accretion from the formation of Enable Midstream Partners, LP.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the threeandsixmonths endedJune 30, 2013as compared to the same period in2012and the Company's consolidated financial position atJune 30, 2013. Due to seasonal fluctuations and other factors, the Company'soperating results for the threeandsixmonths endedJune 30, 2013are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2013or for any future period.The following information should be read in conjunction with theCondensed Consolidated Financial Statements and Notes thereto.Known trends and contingencies of a material nature are discussed to the extent considered relevant.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions except per share data)	2013		2012		2013		2012
Operating income	$	143.9	$	177.3	$	219.3	$	275.6
Net income attributable to OGE Energy	$	91.7	$	93.9	$	114.8	$	131.0
Basic average common shares outstanding (A)	198.3		197.2		198.0		196.8
Diluted average common shares outstanding (A)	199.4		197.8		199.1		197.6
Basic earnings per average common share attributable to OGE Energy common shareholders (A)	$	0.46	$	0.48	$	0.58	$	0.66
Diluted earnings per average common share attributable to OGE Energy common shareholders (A)	$	0.46	$	0.47	$	0.58	$	0.66
Dividends declared per common share (A)	$	0.20875	$	0.19625	$	0.41750	$	0.39250

(A) These amounts have been adjusted to reflect the effects of the stock split.

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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 by Business Segment

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2013			2012		2013			2012
OG&E (Electric Utility)	$	138.1		$	127.8	$	191.0		$	167.6
OGE Holdings (Natural Gas Midstream Operations) (A)	9.0			48.6		33.2			107.2
Other Operations (B)	(3.2		)	0.9		(4.9		)	0.8
Consolidated operating income	$	143.9		$	177.3	$	219.3		$	275.6

(A) The formernatural gas transportation and storagesegment andnatural gas gathering and processingsegment have been combined into thenatural gas midstream operationssegment and have been restated for all prior 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)	2013		2012		2013		2012
Operating revenues	$	574.6	$	528.0	$	1,030.1	$	954.7
Cost of goods sold	247.6		204.6		460.6		400.1
Gross margin on revenues	327.0		323.4		569.5		554.6
Other operation and maintenance	107.0		114.7		212.1		225.3
Depreciation and amortization	62.0		62.7		123.3		122.4
Taxes other than income	19.9		18.2		43.1		39.3
Operating income	138.1		127.8		191.0		167.6
Allowance for equity funds used during construction	1.5		1.7		2.7		3.6
Other income	0.8		0.8		3.5		6.0
Other expense	0.3		0.6		0.8		1.3
Interest expense	33.0		31.1		64.4		62.0
Income tax expense	28.1		25.2		40.0		28.4
Net income	$	79.0	$	73.4	$	92.0	$	85.5
Operating revenues by classification
Residential	$	218.9	$	215.8	$	402.3	$	385.4
Commercial	146.4		134.0		252.0		233.9
Industrial	58.1		51.1		104.2		95.3
Oilfield	48.0		40.7		84.8		77.3
Public authorities and street light	56.0		50.7		97.6		90.1
Sales for resale	15.3		13.1		29.8		25.9
System sales revenues	542.7		505.4		970.7		907.9
Off-system sales revenues	3.3		5.1		5.4		14.0
Other	28.6		17.5		54.0		32.8
Total operating revenues	$	574.6	$	528.0	$	1,030.1	$	954.7
Megawatt-hour sales by classification (In millions)
Residential	2.1		2.2		4.3		4.1
Commercial	1.8		1.8		3.3		3.3
Industrial	1.0		1.0		1.9		2.0
Oilfield	0.8		0.9		1.6		1.7
Public authorities and street light	0.8		0.9		1.5		1.6
Sales for resale	0.3		0.3		0.6		0.6
System sales	6.8		7.1		13.2		13.3
Off-system sales	0.1		0.2		0.2		0.6
Total sales	6.9		7.3		13.4		13.9
Number of customers	801,491		793,998		801,491		793,998
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	4.374		2.576		3.884		2.727
Coal	2.304		2.276		2.295		2.260
Total fuel	3.008		2.275		2.822		2.303
Total fuel and purchased power	3.440		2.669		3.218		2.701
Degree days (A)
Heating - Actual	365		75		2,165		1,457
Heating - Normal	203		203		2,001		2,001
Cooling - Actual	596		793		600		854
Cooling - Normal	625		625		638		638

(A) 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.

34

ThreeMonths EndedJune 30, 2013as Compared toThreeMonths EndedJune 30, 2012

OG&E's operating incomeincreased$10.3 million, or8.1 percent, during thethreemonths endedJune 30, 2013as compared to the same period in2012primarily due a higher gross margin and lower other operation and maintenance expense partially offset by higher taxes other than income.

Gross Margin

Operating revenues were$574.6 millionduring thethreemonths endedJune 30, 2013as compared to$528.0 millionduring the same period in2012, an increaseof$46.6 million, or8.8 percent. Cost of goods sold was$247.6 millionduring thethreemonths endedJune 30, 2013as compared to$204.6 millionduring the same period in2012, an increaseof$43.0 million, or21.0 percent. Gross margin was$327.0 millionduring thethreemonths endedJune 30, 2013as compared to$323.4 millionduring the same period in2012, an increaseof$3.6 million, or1.1 percent. The below factors contributed to the change in gross margin:

	$ Change
	(In millions)
Wholesale transmission revenue (A)	$	11.0
New customer growth	2.6
Price variance (B)	2.6
Non-residential demand and related revenues	(1.3		)
Quantity variance (primarily weather)	(11.3		)
Change in gross margin	$	3.6

(A) Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.

(B) Increased primarily due tosales and customer mixand timing of the Oklahoma rate increase.

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.Fuel expense was$170.8 millionduring thethreemonths endedJune 30, 2013as compared to$145.8 millionduring the same period in2012, an increaseof$25.0 million, or17.1 percent, primarily due to higher natural gas 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 OG&E and its customers.Purchased power costs were$70.8 millionduring thethreemonths endedJune 30, 2013as compared to$55.7 millionduring the same period in2012, an increaseof$15.1 million, or27.1 percent, primarily due to an increase in purchases in the energy imbalance service market. Transmission-related charges were$6.0 millionduring thethreemonths endedJune 30, 2013as compared to$3.1 millionduring the same period in2012, an increaseof$2.9 million, or93.5 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

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 its affiliate, OGE Holdings.

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Operating Expenses

Other operation and maintenance expense was$107.0 millionduring thethreemonths endedJune 30, 2013as compared to$114.7 millionduring the same period in2012, a decreaseof$7.7 million, or6.7 percent. The below factors contributed to the change in other operation and maintenance expense:

	$ Change
	(In millions)
Ongoing maintenance at power plants (A)	$	(5.5	)
Employee benefits (B)	(2.9		)
Regular salaries and wages (C)	(1.3		)
Other	(0.1		)
Overtime wages (D)(E)	2.1
Change in other operation and maintenance expense	$	(7.7	)

(A) Decreased due to delay in timing of outages to later in 2013.

(B) Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case.

(C) Decreased primarily due to lower headcount in 2013.

(D) Increased primarily due to recovery efforts from May 2013 storms.

(E) Includes costs that are being recovered through a rider.

Depreciation and amortization expense was$62.0 millionduring thethreemonths endedJune 30, 2013as compared to$62.7 millionduring the same period in2012, a decreaseof$0.7 million, or1.1 percent, primarily due to the amortization of the deferred Pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1).These decreases in depreciation and amortization expense were partially offset by:

• changes in depreciation rates from the August 2012 rate case; and

• additional assets being placed in service throughout 2012 and thesixmonths endedJune 30, 2013, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland transmission project which was fully in service in February 2013.

Additional Information

Income Tax Expense.Income tax expense was$28.1 millionduring thethreemonths endedJune 30, 2013as compared to$25.2 millionduring the same period in2012, an increaseof$2.9 millionor11.5 percent, primarily due tohigherpre-tax income partially offset by an increase in the amount of Federal production tax credits recognized during thethreemonths endedJune 30, 2013as compared to the same period in2012.

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SixMonths EndedJune 30, 2013as Compared toSixMonths EndedJune 30, 2012

OG&E's operating incomeincreased$23.4 million, or14.0 percent, during thesixmonths endedJune 30, 2013as compared to the same period in2012primarily due to a higher gross margin and lower other operation and maintenance expense partially offset by higher taxes other than income.

Gross Margin

Operating revenues were$1,030.1 millionduring thesixmonths endedJune 30, 2013as compared to$954.7 millionduring the same period in2012, an increaseof$75.4 million, or7.9 percent. Cost of goods sold was$460.6 millionduring thesixmonths endedJune 30, 2013as compared to$400.1 millionduring the same period in2012, an increaseof$60.5 million, or15.1 percent. Gross margin was$569.5 millionduring thesixmonths endedJune 30, 2013as compared to$554.6 millionduring the same period in2012, an increaseof$14.9 million, or2.7 percent. The below factors contributed to the change in gross margin:

	$ Change
	(In millions)
Wholesale transmission revenue (A)	$	20.6
New customer growth	5.2
Other	0.5
Quantity variance (primarily weather)	(2.3		)
Price variance (B)	(9.1		)
Change in gross margin	$	14.9

(A) Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.

(B) Decreased primarily due tosales and customer mix.

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.Fuel expense was$317.3 millionduring thesixmonths endedJune 30, 2013as compared to$288.9 millionduring the same period in2012, an increaseof$28.4 million, or9.8 percent, primarily due to higher natural gas pricespartially offset by lower 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 OG&E and its customers.Purchased power costs were$130.8 millionduring thesixmonths endedJune 30, 2013as compared to$104.7 millionduring the same period in2012, an increaseof$26.1 million, or24.9 percent, primarily due to an increase in purchases in the energy imbalance service market. Transmission-related charges were$12.5 millionduring thesixmonths endedJune 30, 2013as compared to$6.5 millionduring the same period in2012, an increaseof$6.0 million, or92.3 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

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Operating Expenses

Other operation and maintenance expense was$212.1 millionduring thesixmonths endedJune 30, 2013as compared to$225.3 millionduring the same period in2012, a decreaseof$13.2 million, or5.9 percent. The below factors contributed to the change in other operation and maintenance expense:

	$ Change
	(In millions)
Employee benefits (A)	$	(6.1	)
Ongoing maintenance at power plants (B)	(5.7		)
Regular salaries and wages (C)	(2.8		)
Corporate overheads and allocations (D)	(2.0		)
Demand side management customer payments (E)	(1.3		)
Other	0.7
Capitalized labor	1.8
Overtime wages (E)(F)	2.2
Change in other operation and maintenance expense	$	(13.2	)

(A) Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case.

(B) Decreased due to delay in timing of outages to later in 2013.

(C) Decreased primarily due to lower headcount in 2013.

(D) Decreased primarily due to decreases in depreciation expense, software expense, contract technical expense and sales, marketing and commercial expenses from the holding company.

(E) Includes costs that are being recovered through a rider.

(F) Increased primarily due to recovery efforts from May 2013 storms.

Depreciation and amortization expense was$123.3 millionduring thesixmonths endedJune 30, 2013as compared to$122.4 millionduring the same period in2012, an increaseof$0.9 million, or0.7 percent, primarily due to:

• changes in depreciation rates from the August 2012 rate case; and

• additional assets being placed in service throughout 2012 and thesixmonths endedJune 30, 2013, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland transmission project which was fully in service in February 2013.

These increases in depreciation and amortization expense were partially offset by the amortization of the deferred Pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1).

Taxes other than income was$43.1 millionduring thesixmonths endedJune 30, 2013as compared to$39.3 millionduring the same period in2012, an increaseof$3.8 million, or9.7 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$2.7 millionduring thesixmonths endedJune 30, 2013as compared to$3.6 millionduring the same period in2012, a decreaseof$0.9 million, or25.0 percentprimarily due to a lower return on equity investments.

Other Income.Other income was$3.5 millionduring thesixmonths endedJune 30, 2013as compared to$6.0 millionduring the same period in2012, a decreaseof$2.5 million, or41.7 percent. Thedecreasein other income was primarily due toa decreasedmargin of$2.1 millionrecognized in the guaranteed flat bill program during thesixmonths endedJune 30, 2013as a result of lower usage.

Income Tax Expense.Income tax expense was$40.0 millionduring thesixmonths endedJune 30, 2013as compared to$28.4 millionduring the same period in2012, an increaseof$11.6 million, or40.8 percentprimarily due toa reserve related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized,higherpre-tax income and

38

an increase in the amount of Federal production tax credits recognized during thesixmonths endedJune 30, 2013as compared to the same period in2012.

OGE Holdings (Natural Gas Midstream Operations)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Operating revenues	$	166.1	$	344.0	$	630.4	$	773.6
Cost of goods sold	129.7		222.6		489.0		527.9
Gross margin on revenues	36.4		121.4		141.4		245.7
Other operation and maintenance	15.7		42.7		60.9		85.0
Depreciation and amortization	9.2		24.3		36.8		47.7
Impairment of assets	—		0.1		—		0.3
Gain on insurance proceeds	—		—		—		(7.5		)
Taxes other than income	2.5		5.7		10.5		13.0
Operating income	9.0		48.6		33.2		107.2
Equity in earnings of unconsolidated affiliates	18.5		—		18.5		—
Other income	0.1		—		10.2		0.2
Other expense	0.1		0.1		1.3		0.7
Interest expense	2.5		7.4		10.6		15.0
Income tax expense	8.8		12.6		16.3		27.9
Net income	16.2		28.5		33.7		63.8
Less: Net income attributable to noncontrolling interests	1.4		7.5		6.6		17.9
Net income attributable to OGE Holdings	$	14.8	$	21.0	$	27.1	$	45.9

Effective May 1, 2013, the Company deconsolidated its previously held investment in Enogex Holdings and acquired a 28.5 percent equity interest in Enable Midstream Partners which is being accounted for using the equity method of accounting. The formernatural gas transportation and storagesegment andnatural gas gathering and processingsegment have been combined into thenatural gas midstream operationssegment and have been restated for all prior periods presented. All financial statement line items included in the table above (except equity in earnings of unconsolidated affiliates and income tax expense) reflect 2013 operations only through April 30, 2013 and are not comparable to the prior year due to the deconsolidation discussed above. Equity in earnings of unconsolidated affiliates reflects OGE Energy's 28.5 percent equity interest in the earnings of Enable Midstream Partners for May 2013 and June 2013 and was $18.5 million with no comparable item in the prior year. See below for a discussion of the results of operations.

ThreeMonths EndedJune 30, 2013as Compared toThreeMonths EndedJune 30, 2012

	Natural Gas Midstream Operations (Consolidated - Month Ended April 30, 2013)		Enable Midstream Partners (Equity Method - Two Months Ended June 30, 2013)		Total (Three Months Ended June 30, 2013)		Natural Gas Midstream Operations (Consolidated - Three Months Ended June 30, 2012)
(In millions)
Gross margin on revenues	$	36.4	$	—	$	36.4	$	121.4
Operating expenses	27.4		—		27.4		72.8
Equity in earnings of unconsolidated affiliates	—		18.5		18.5		—
Income tax expense	1.9		6.9		8.8		12.6
Net income	3.2		11.6		14.8		21.0

39

SixMonths EndedJune 30, 2013as Compared toSixMonths EndedJune 30, 2012

	Natural Gas Midstream Operations (Consolidated - Four Months Ended April 30, 2013)		Enable Midstream Partners (Equity Method - Two Months Ended June 30, 2013)		Total (Six Months Ended June 30, 2013)		Natural Gas Midstream Operations (Consolidated - Six Months Ended June 30, 2012)
(In millions)
Gross margin on revenues	$	141.4	$	—	$	141.4	$	245.7
Operating expenses	108.2		—		108.2		138.5
Equity in earnings of unconsolidated affiliates	—		18.5		18.5		—
Income tax expense	9.4		6.9		16.3		27.9
Net income	15.5		11.6		27.1		45.9

OGE Holdings' results of operations for April 2013 and the four months ended April 2013 as compared to the same period of 2012 decreased due to lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex LLC's five largest customers from keep-whole to fixed-fee, in addition to slightly higher other operation and maintenance expense and depreciation and amortization expense.These decreases were partially offset byincreased gathering rates and volumes and inlet processing volumes associated with ongoing expansion projects and the gas gathering assets acquired in August 2012.

Enable Midstream Partners' results for the two months ended June 30, 2013, were consistent with management's expectations in light of lower natural gas liquids prices and low seasonal and geographic price differentials. Enable Midstream Partners' continued to increase gathering and processing volumes through system expansions. Transportation throughput was impacted by system integrity projects and slightly lower demand.

Income taxes during the three and six months ended June 30, 2013 as compared to the same period in 2012 decreased due to the Company having a lower effective tax rate in conjunction with the formation of Enable Midstream Partners in states with lower state tax rates, deferred tax adjustments related to the Company's deconsolidation of Enogex Holdings and lower pre-tax income (net of noncontrolling interest).

Enable Midstream Partners Results of Operations during the TwoMonths EndedJune 30, 2013

	Two Months Ended
	June 30, 2013
	(In millions)
Gross margin	$	207.4
Operating expenses	132.4
Net income	65.1

Enable Midstream Partners Operating Data during the TwoMonths EndedJune 30, 2013

	Two Months Ended
	June 30, 2013
Gathered volumes - TBtu/d (A)	3.6
Transportation volumes - TBtu/d	5.2
NGLs processed - million gallons	88.0

(A) Excludes volumes billed under throughput agreements.

40

Off-Balance Sheet Arrangement

There have been no significant changes in the Company's off-balance sheet arrangement from that discussed in the Company's 2012Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

Liquidity and Capital Resources

Working Capital

Working capital is defined as the amount by which current assets exceed current liabilities. The Company's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.

The balance of Accounts Receivable and Accrued Unbilled Revenues was$279.0 millionand$352.7 millionatJune 30, 2013andDecember 31, 2012, respectively,a decreaseof$73.7 million, or20.9 percent, primarily due to the deconsolidation of Enogex Holdings on May 1, 2013 partially offset by an increase in OG&E's billings to customers reflecting warmer weather in June 2013 as compared to December 2012.

The balance of Accounts Payable was$219.6 millionand$396.7 millionatJune 30, 2013andDecember 31, 2012, respectively,a decreaseof$177.1 million, or44.6 percent, primarily due to the deconsolidation of Enogex Holdings on May 1, 2013 partially offset by an increase in accruals.

Cash Flows

	Six Months Ended
	June 30,						2013 vs. 2012
(In millions)	2013			2012			$ Change			% Change
Net cash provided from operating activities	$	79.9		$	281.5		$	(201.6	)	(71.6	)%
Net cash used in investing activities	(531.8		)	(526.9		)	(4.9		)	(0.9	)%
Net cash provided from financing activities	450.1			242.5			207.6			85.6	%

Operating Activities

Thedecrease of $201.6 million, or 71.6 percent, in net cash provided from operating activities during thesixmonths endedJune 30, 2013as compared to the same period in2012was primarily due to:

• fuel refunds at OG&E during thesixmonths endedJune 30, 2013as compared to higher fuel recoveries in the same period in2012; and

• the deconsolidation of Enogex Holdings on May 1, 2013.

These decreases in net cash provided from operating activities were partially offset by an increase in cash receivedduring thesixmonths endedJune 30, 2013 from transmission revenue.

Investing Activities

Theincrease of $4.9 million, or 0.9 percent, in net cashused ininvesting activitiesduring thesixmonths endedJune 30, 2013as compared to the same period in2012was primarily due tohigher levels of capital expendituresduring thesixmonths endedJune 30, 2013related to various transmission projects at OG&E partially offset by proceeds received from OGE Holdings' sale of certain gas gathering assets in the Texas Panhandle.

Financing Activities

Theincrease of $207.6 million, or 85.6 percent, in net cash provided from financing activitiesduring thesixmonths endedJune 30, 2013as compared to the same period in2012 was primarily due to:

• proceeds received from OG&E's issuance of long-term debt in May 2013;

41

• payments on advances from unconsolidated affiliates due to the deconsolidation of Enogex Holdings on May 1, 2013; and

• and a contribution of $107.0 million from the Arclight group immediately prior to the closing of the transaction to form Enable Midstream Partners.

These increases in net cash provided from financing activities are partially offset by a decrease in short-term debt borrowings during the sixmonths endedJune 30, 2013 as compared to the same period in 2012.

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. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings. OGE Energy believes that Enable Midstream Partners has, or will have access to, adequate liquidity and, therefore, no contributions are expected to be necessary to fund the capital expenditures of Enable Midstream Partners from the general partners. Accordingly, capital expenditures for Enable Midstream Partners are not included in the table below.

Capital Expenditures

The Company's consolidated estimates of capital expenditures for the years 2013 through 2017 are shown in the following table.These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company's business) plus capital expenditures for known and committed projects.

(In millions)	2013		2014		2015		2016		2017
OG&E Base Transmission	$	70	$	50	$	50	$	50	$	50
OG&E Base Distribution	205		175		175		175		175
OG&E Base Generation	100		125		75		75		75
OG&E Other	15		15		15		15		15
Total OG&E Base Transmission, Distribution, Generation and Other	390		365		315		315		315
OG&E Known and Committed Projects:
Transmission Projects:
Balanced Portfolio 3E Projects (A)	185		20		—		—		—
SPP Priority Projects (A)	180		80		—		—		—
SPP Integrated Transmission Projects (A)	5		5		—		40		40
Total Transmission Projects	370		105		—		40		40
Other Projects:
Smart Grid Program	25		25		10		10		—
System Hardening	15		—		—		—		—
Environmental - low NOX burners	20		30		25		20		—
Total Other Projects	60		55		35		30		—
Total OG&E Known and Committed Projects	430		160		35		70		40
Total OG&E (B)	820		525		350		385		355
OGE Energy	10		10		10		10		10
Total capital expenditures	$	830	$	535	$	360	$	395	$	365

42

(A)	Project Type	Project Description	Estimated Cost (In millions)	Projected In-Service Date
	Balanced Portfolio 3E	135 miles of transmission line from OG&E's Seminole substation to OG&E's Muskogee substation	$175	Late 2013
	Balanced Portfolio 3E	96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the Oklahoma /Texas Stateline to a companion transmission line to its Tuco substation	$115	Mid-2014
	Priority Project	99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the western Beaver County line to a companion transmission line to its Hitchland substation	$165	Mid-2014
	Priority Project	77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border	$140	Late 2014
	Integrated Transmission Project	47 miles of transmission line from OG&E's Gracemont substation to a companion transmission line to its Elk City substation	$75	Early 2018
	Integrated Transmission Project	126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation; construction of the Mathewson substation on this transmission line	$210	Early 2021

(B) The capital expenditures above exclude any environmental expenditures associated with:

• Pollution control equipment related to controlling SO₂emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment.The SO₂emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry Scrubbers could cost more than$1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit.On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. OG&E will file with the Tenth Circuit a request for a rehearing on or before September 3, 2013. Unless a rehearing is granted, the stay will be lifted in the near future. If the stay is lifted, OG&E will have approximately 55 months from the date the stay is lifted to achieve compliance with the FIP.The Companycannot predict whether its rehearing request will be granted or the final outcome of this matter. As noted above, compliance with the FIP could require capital costs of more than$1.0 billion.

• Installation of control equipment for compliance with Mercury and Air Toxics Standards by a deadline of April 16, 2015, with the possibility of a one-year extension. OG&E is currently planning to utilize activated carbon injection and low levels of dry sorbent injection at each of its five coal-fired units. Due to various uncertainties about the final design, the potential use of this technology relating to regional haze measures and the specifications for the control equipment, the resulting cost estimates currently range from$34 millionto$72 millionper unit.

OG&E is currently evaluating options to comply with environmental requirements. For further information, see "Environmental Laws and Regulations" below.

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

Contractual Obligations

Except as set forth below, the circumstances set forth in Contractual Obligations in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's 2012Form 10-K appropriately represent, in all material respects, the current status of the Company's contractual obligations.

(In millions)	2013		2014-2015		2016-2017		After 2017		Total
Other purchase obligations and commitments
OG&E long-term service agreement commitments	$	19.0	$	77.0	$	5.0	$	136.7	$	237.7

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Pension Plan Funding

The Companypreviously reported in its 2012 Form 10-K that it may contribute up to$35 millionto its Pension Plan during 2013. In May 2013,the Companycontributed$35 millionto its Pension Plan. No additional contributions are expected in 2013.

Security Ratings

Access to reasonably priced capital is dependent in part on credit and security ratings.Generally, lower ratings lead to higher financing costs.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 downgradecould 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 conjunction with the closing of Enable Midstream Partners on May 1, 2013, on May 2, 2013, Standard & Poor's Ratings Services upgraded the long-term senior unsecured rating of OGE Energy to BBB+ and OG&E to A-. All other security ratings as previously reported in the Company's 2012 Form 10-K remain unchanged.

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

Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt, distributions from equity method investments and proceeds from the sales ofcommon stock to the public through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan or other offeringswill be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. The Company utilizes short-term borrowings (through a combination of bank borrowings 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 CreditFacilities

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. At June 30, 2013, the Company has revolving credit facilities totaling in the aggregate $1,150 million. These bank facilities can also be used asletter of credit facilities. The short-term debt balance was$478.7 millionand$430.9 millionatJune 30, 2013andDecember 31, 2012, respectively. The weighted-average interest rate on short-term debt at June 30, 2013 was 0.31 percent.  The average balance of short-term debt during the three months ended June 30, 2013 was $507.9 million at a weighted-average interest rate of 0.34 percent. The maximum month-end balance of short-term debt during the three months ended June 30, 2013 was $609.7 million. AtJune 30, 2013, there was$2.1 millionsupporting letters of credit at a weighted-average interest rate of0.53 percent. At June 30, 2013, the Company had $669.2 millionof net available liquidity under its revolving credit agreements.  OG&E has the necessary regulatory approvals to incur up to$800 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2013 and ending December 31, 2014.  At June 30, 2013, the Company had less than $0.1 million in cash and cash equivalents.  See Note 10 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

Effective May 1, 2013, Enable Midstream Partnersentered into a$1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's$400 millionrevolving credit facility was terminated.

In December 2011,the Company andOG&E entered intounsecured five-year revolving credit agreements to total in the aggregate$1,150 million ($750 millionfor the Company and$400 millionfor OG&E).Each of thecredit facilitiescontainan option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013,the Company andOG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity oftheircredit agreementsto December 13, 2017.

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Issuance of New Long-Term Debt

On May 8, 2013, OG&E issued$250 millionof3.9%senior notes dueMay 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures, general corporate expenses and for working capital purposes. 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 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 for all Company segments includes the determination of Pension Plan assumptions,impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas midstream operations segment, the most significant judgment is also exercised in the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill and equity method investments. 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 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's 2012Form 10-K.

Commitments and Contingencies

In the normal course of business,the Companyis confronted with issues or events that may result in a contingent liability.These generally relate to lawsuits or claims made by third parties, including governmental agencies.When appropriate, management consults with legal counsel and other appropriate experts to assess the claim.If, in management's opinion,the Companyhas 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.At the present time, based on currently available information, except as otherwise stated in Notes 13 and 14 of Notes to Condensed Consolidated Financial Statements, under "Environmental Laws and Regulations" below and in Item 1 of Part II of this Form 10-Q, in Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I of the Company's 2012Form 10-K, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

Environmental Laws and Regulations

The activities of OG&E 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 business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards. 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 2012Form 10-K. Except as set forth below, there have been no material changes to such items.

OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below 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.

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Air

Regional Haze Control Measures

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous sources over a wide geographic area. The regional haze rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the rule. However, Oklahoma's impact on parks in other states must also be evaluated.

As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977. Certain of OG&E’s units at the Horseshoe Lake, Seminole, Muskogee and Sooner generating stations were evaluated for BART. 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 was subject to the EPA's review and approval.

The Oklahoma SIP included requirements for reducing emissions of NOX and SO₂from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NOX emissions at all of the subject units should be the installation of low NOX burners with overfire air (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 capital cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be approximately$95 million.With respect to SO₂ emissions, the SIP included an agreement between the Oklahoma Department of Environmental Quality and OG&E that established BART for SO₂control at the four affected 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 SO₂control from these units because the state determined that Dry Scrubbers were not cost effective on these units.

On December 28, 2011, the EPA issued a final rule in which it rejected portions of the Oklahoma SIP and issued a FIP in their place. While the EPA accepted Oklahoma's BART determination for NOX in the final rule, it rejected Oklahoma's SO₂BART determination with respect to the four coal-fired units at the Sooner and Muskogee generating stations. The EPA is instead requiring that OG&E meet an SO₂emission rate of0.06pounds per million British thermal unit within five years. OG&E could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four affected units. OG&E estimates that installing Dry Scrubbers on these units would include capital costs to OG&E of more than$1.0 billion. OG&E and the state of Oklahoma filed an administrative stay request with the EPA on February 24, 2012. The EPA has not yet responded to this request. OG&E and other parties also filed a petition for review of the FIP in the U.S. Court of Appeals for the Tenth Circuit on February 24, 2012 and a request to stay the FIP on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the Tenth Circuit granted the stay request.On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. OG&E will file with the Tenth Circuit a request for a rehearing on or before September 3, 2013. Unless a rehearing is granted, the stay will be lifted in the near future. If the stay is lifted, OG&E will have approximately 55 months from the date the stay is lifted to achieve compliance with the FIP.The Companycannot predict whether its rehearing request will be granted or the final outcome of this matter. As noted above, compliance with the FIP could require capital costs of more than$1.0 billion.

Cross-State Air Pollution Rule

As previously reported, 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. The final rule would require 27states to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. On December 27, 2011, the EPA published a supplemental rule, which would make sixadditional states, including Oklahoma, subject to the Cross-State Air Pollution Rule for NOX emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. The Cross-State Air Pollution Rule was challenged in court by numerous states and power generators. On December 30, 2011, the U.S. Court of Appeals issued a stay of the rule, which includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the U.S. Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA to promulgate a replacement rule. On June 24, 2013, the U.S. Supreme Court agreed to review the decision by the U.S. Court of Appeals, with a decision expected during the first half of 2014. OG&E cannot predict the outcome of such challenges.

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United States v. OG&E (Federal Clean Air Act New Source Review Litigation)

As previously reported, in July 2008, OG&E 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. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects 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.

In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with the EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. OG&E expects to vigorously defend against these claims, but OG&E cannot predict the outcome of such litigation. The Sierra Club, an environmental organization, also has threatened to file a citizen suit under the Federal Clean Air Act alleging similar violations against OG&E, and OG&E expects that the Sierra Club will seek to intervene in the litigation initiated by the EPA. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act.

If OG&E does not prevail and if a new assessment of the projects were to conclude that they caused a significant emissions increase, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including Dry Scrubbers and selective catalytic reduction systems with capital costs in excess of$1.0 billionand pay fines and significant 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$37,500per day for each violation. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs.

Climate Change and Greenhouse Gas Emissions

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including carbon dioxide, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the Earth's atmosphere.  There are various international agreements that restrict greenhouse gas emissions, but none of them have a binding effect on sources located in the United States. The U.S. Congress has not passed legislation to reduce emissions of greenhouse gases and the future prospects for any such legislation are uncertain, but the EPA has existing authority under the Clean Air Act to regulate greenhouse gas emissions from stationary sources. Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Oklahoma and Arkansas are not among them. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on the Company's facilities, this could result in significant additional compliance costs that would affect the Company’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

Following from the Supreme Court's interpretation of the Clean Air Act's applicability to greenhouse gases in Massachusetts v. EPA, the EPA has proposed regulations for new power plants.  In June 2013, President Obama instructed the EPA to finalize those rules in 2014 and to require states to submit rules for existing power plants in 2016.  It is uncertain if the EPA will adhere to this schedule, and the substance of any rules that the EPA may issue is unknown.  OG&E cannot predict the financial impacts of these rules.

Endangered Species

Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats.  If such species are located in an area in which the Company conducts operations,

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or if additional species in those areas become subject to protection, the Company’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company could be required to implement expensive mitigation measures. The U.S. Fish and Wildlife Service announced a proposed rule to list the lesser prairie chicken as threatened on November 30, 2012. A final decision regarding listing is anticipated to be completed by March 30, 2014. Although the lesser prairie chicken and its habitat are located in potential development areas of the Company, the impact of a final decision to list this species as threatened cannot be determined at this time.

Water

OG&E's operations are subject to the Federal Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. The Federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Existing cooling water intake structures are regulated under the Federal Clean Water Act to minimize their impact on the environment.

With respect to cooling water intake structures, Section 316(b) of the Federal Clean Water Act requires that their location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. In March 2011, the EPA proposed rules to implement Section 316(b). On August 18, 2011, OG&E filed comments with the EPA on the proposed rules. In June 2012, the EPA published a Notice of Data Availability requesting additional comments on a number of impingement mortality-related issues based on new information received during the initial public comment period. On July 11, 2012, OG&E filed comments regarding the Notice of Data Availability. In July 2012, the EPA entered into a settlement agreement in a pending litigation matter, which extended the deadline by which the proposed rules will be finalized to June 2013. On June 27, 2013 the EPA signed an amendment to the previous settlement agreement to finalize the proposed rules by November 4, 2013. In the interim, the state of Oklahoma requires OG&E to implement best management practices related to the operation and maintenance of its existing cooling water intake structures as a condition of renewing its discharge permits. Once the EPA promulgates the final rules, OG&E may incur additional capital and/or operating costs to comply with them. 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.

There have been no significant changes in the market risks affecting the Company from those discussed in the Company's 2012 Form 10-K.

Item 4.  Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure. The Company has an investment in an unconsolidated affiliate (see Note 3 of Notes to Condensed Consolidated Financial Statements). As the Company does not control this affiliate, its disclosure controls and procedures with respect to such affiliate is more limited than those the Company maintains with respect to its consolidated subsidiaries. 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).

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2012Form 10-K for a description of certain legal proceedings presently pending. Except as described above under Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," 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.

Item 1A.  Risk Factors.

Except as discussed below, there have been no significant changes in the Company's risk factors from those discussed in the Company's 2012Form 10-K, which are incorporated herein by reference.

Enable Midstream Partners may not be able to successfully integrate the operations of OGE Holdings and CenterPoint.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributed100 percentof the equity interests inEnogex LLCto Enable Midstream Partners. CenterPoint Energy Field Services, LLCwas converted into a Delaware limited partnership that became Enable Midstream Partners. CenterPoint contributed to Enable Midstream Partners its equity interests in each of (i) CenterPoint Energy Gas Transmission Company, LLC, (ii) MRT, and (iii) certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute a24.95 percentinterest in Southeast Supply Header, LLC.  If Enable Midstream Partners is not able to successfully integrate these operations, it could have an adverse impact on our financial position, results of operations or cash flows.

Effective May 1, 2013, OGE Energy does not control Enogex Holdings LLC or Enable Midstream Partners, and therefore is not able to cause or prevent certain actions by Enable Midstream Partners.

Enable Midstream Partners has its own governing board, and OGE Energy will not control all of the decisions of that board. Consequently, OGE Energy will be unable solely to cause Enable Midstream Partners to take actions that OGE Energy believes would be in our or Enable Midstream Partners' best interests. Likewise, OGE Energy will be unable to prevent certain actions of Enable Midstream Partners.

The Company's operating cash flow is derived partially from cash distributions the Company receives from its unconsolidated affiliate.

The Company's operating cash flow is derived partially from cash distributions the Company receives from its unconsolidated affiliate. The amount of cash that the Company's unconsolidated affiliate can distribute principally depends upon the amount of cash flow this affiliate generates from its operations, which may fluctuate from quarter to quarter. The Company does not have any direct control over the cash distribution policies of the Company's unconsolidated affiliate.

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

The following table contains information about the Company's purchases of its common stock during the second quarter of 2013.

Period	Total Number of Shares Purchased		Average Price Paid Per Share			Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
4/1/13 - 4/30/13	5,810	(A)(B)	$	35.03	(B)	N/A	N/A
5/1/13 - 5/31/13	—		$	—		N/A	N/A
6/1/13 - 6/30/13	—		$	—		N/A	N/A

(A) These shares of restricted stock were returned to the Company to satisfy tax liabilities.

(B) These shares of restricted stock and the average price paid per share were adjusted for the effects of the stock split.

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Item 6.  Exhibits.

Exhibit No.	Description
3.01	Copy of Restated OGE Energy Corp. Certificate of Incorporation.
4.01	Supplemental Indenture No. 13 dated as of May 1, 2013 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 13, 2013 (File No. 1-1097) and incorporated by reference herein)
10.01	First Amended and Restated Agreement of Limited Partnership of CenterPoint Energy Field Services LP dated as of May 1, 2013 (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed May 7, 2013 (File No. 1-12579) and incorporated by reference herein)
10.02	Amended and Restated Limited Liability Company Agreement of CNP OGE GP LLC dated as of May 1, 2013 (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed May 7, 2013 (File No. 1-12579) and incorporated by reference herein)
10.03	Registration Rights Agreement dated as of May 1, 2013 by and among CenterPoint Energy Field Services LP, CenterPoint Energy Resources Corp., OGE Enogex Holdings LLC, and Enogex Holdings LLC (Filed as Exhibit 10.03 to OGE Energy's Form 8-K filed May 7, 2013 (File No. 1-12579) and incorporated by reference herein)
10.04	Omnibus Agreement dated as of May 1, 2013 among CenterPoint Energy, Inc., OGE Energy Corp., Enogex Holdings LLC and CenterPoint Energy Field Services LP (Filed as Exhibit 10.04 to OGE Energy's Form 8-K filed May 7, 2013 (File No. 1-12579) and incorporated by reference herein)
10.05*	OGE Energy's 2013 Stock Incentive Plan. (Filed as Annex B to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)
10.06*	OGE Energy's 2013 Annual Incentive Compensation Plan. (Filed as Annex C to OGE Energy's Proxy Statement for the 2013 Annual Meeting of Shareowners (File No. 1-12579) and incorporated by reference herein)
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Description of Capital Stock.
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.
* Represents executive compensation plans and arrangements.

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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
	(On behalf of the Registrant and in his capacity as Chief Accounting Officer)

August 8, 2013

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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 455,000,000 shares, of which 450,000,000 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)the rate or rates of dividends applicable to shares of such series,

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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 Preferred Stock or such of the series of the Preferred Stock as are from time to time

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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.

(1)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:

(a)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

(b)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

(c)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

(d)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

(e)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.

(2)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:

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

(2)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:

(1)A "person" shall mean any individual, firm, corporation or other entity.

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

(a)is the beneficial owner, directly or indirectly of more than 10% of the voting power of the outstanding Voting Stock; or

(b)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

(c)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.

(3)A person shall be a "beneficial owner" of any Voting Stock:

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

(b)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

(c)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.

(4)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.

(5)"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.

(6)"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.

(7)"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.

(8)"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.

(9)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.

(10)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 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

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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.

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(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

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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

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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.

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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.]

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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, President and Chief Executive Officer and attested to by its Corporate Secretary, this 25th day of July, 2013.

		OGE Energy Corp., an Oklahoma corporation
		By:	/s/ Peter B. Delaney
		Name:	Peter B. Delaney
		Title:	Chairman of the Board, President 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 25th day of July, 2013, by Peter D. Delaney, as Chairman of the Board, President and Chief Executive Officer of OGE Energy Corp., an Oklahoma corporation.

(SEAL)	/s/ Sharlette Deviney
	Notary Public
	My Commission Expires:	June 19, 2016
	My Commission Number:	12005693

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EX-31.01

Exhibit 31.01

CERTIFICATIONS

I, Peter B. Delaney, certify that:

1. I have reviewed this quarterly report on Form 10-Q ofOGE 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 8, 2013

  /s/ Peter B. Delaney

       Peter B. Delaney

Chairman of the Board, President and Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, Sean Trauschke, certify that:

1. I have reviewed this quarterly report on Form 10-Q ofOGE 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 8, 2013

  /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 endedJune 30, 2013, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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 8, 2013

          /s/ Peter B. Delaney

               Peter B. Delaney

Chairman of the Board, President and Chief Executive Officer

          /s/ Sean Trauschke

               Sean Trauschke

Vice President and Chief Financial Officer

EX-99.01

Exhibit 99.01

DESCRIPTION OF CAPITAL STOCK

The following statements are summaries of certain provisions of our Restated Certificate of Incorporation and are subject to the detailed provisions thereof. Such summaries do not purport to be complete, and reference is made to our Restated Certificate of Incorporation (which is filed as Exhibit 3.01 to our Form 10-Q for the quarter ended June 30, 2013, File No. 1-12579) for a full and complete statement of such provisions.

Authorized Shares

Under our Restated Certificate of Incorporation, we are authorized to issue 450,000,000 shares of common stock, par value $0.01 per share, of which 198,353,947 shares were outstanding on July 15, 2013.

We are also authorized to issue 5,000,000 shares of preferred stock, par value $0.01 per share. No shares of preferred stock are currently outstanding. Without shareholder approval, we may issue preferred stock in the future in such series as may be designated by our board of directors. In creating any such series, our board of directors has the authority to fix the rights and preferences of each series with respect to, among other things, the dividend rate, redemption provisions, liquidation preferences, sinking fund provisions, conversion rights and voting rights. The terms of any series of preferred stock that we may issue in the future may provide the holders of such preferred stock with rights that are senior to the rights of the holders of our common stock.

Dividend Rights

Before we can pay any dividends on our common stock, the holders of our preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. Currently, there are no shares of our preferred stock outstanding. Because we are a holding company and conduct all of our operations through our subsidiaries, our cash flow and ability to pay dividends will be dependent on the earnings and cash flows of our subsidiaries and other equity interests and the distribution or other payment of those earnings to us in the form of dividends or distributions, or in the form of repayments of loans or advances to us. We expect to derive principally all of the funds required by us to enable us to pay dividends on our common stock from dividends paid by OG&E, on OG&E's common stock, and from distributions paid by OGE Enogex Holdings LLC, on OGE Enogex Holdings' limited liability company interests, including distributions from its equity interests. Our ability to receive dividends on OG&E's common stock is subject to the prior rights of the holders of any OG&E preferred stock that may be outstanding, any covenants of OG&E's certificate of incorporation and OG&E's debt instruments limiting the ability of OG&E to pay dividends and the ability of public utility commissions that regulate OG&E to effectively restrict the payment of dividends by OG&E. Our ability to receive distributions on OGE Enogex's limited liability company interests is subject to the prior rights of existing and future holders of such limited liability company interests that may be outstanding and any covenants in the debt instruments of OGE Enogex and its subsidiaries and equity interests limiting the ability to pay distributions.

Voting Rights

Each holder of common stock is entitled to one vote per share upon all matters upon which shareowners have the right to vote and generally will vote together as one class. Our board of directors has the authority to fix conversion and voting rights for any new series of preferred stock (including the right to elect directors upon a failure to pay dividends), provided that no share of preferred stock can have more than one vote per share.

Our Restated Certificate of Incorporation also contains "fair price" provisions, which require the approval by the holders of at least 80 percent of the voting power of our outstanding voting stock as a condition for mergers, consolidations, sales of substantial assets, issuances of capital stock and certain other business combinations and transactions involving us and any substantial (10 percent or more) holder of our voting stock unless the transaction is either approved by a majority of the members of our board of directors who are unaffiliated with the substantial holder or specified minimum price and procedural requirements are met. The provisions summarized in the foregoing sentence may be amended only by the approval of the holders of at least 80 percent of the voting power of our outstanding voting stock. Our voting stock consists of all outstanding shares entitled to vote generally in the election of directors and currently consists of our common stock.

Our voting stock does not have cumulative voting rights for the election of directors. Our Restated Certificate of Incorporation and By-Laws currently contain provisions stating that: (1)  directors may be removed only with the approval of the holders of at least a majority of the voting power of our shares generally entitled to vote; (2) any vacancy on the board of directors will be filled only by the remaining directors then in office, though less than a quorum; (3) advance notice of introduction by shareowners of business at annual shareowner meetings and of shareowner nominations for the election of directors must be given

and that certain information must be provided with respect to such matters; (4) shareowner action may be taken only at an annual meeting of shareowners or a special meeting of shareowners called by the President or the board of directors; and (5) the foregoing provisions may be amended only by the approval of the holders of at least 80 percent of the voting power of the shares generally entitled to vote. These provisions, along with the "fair price" provisions discussed above, the business combination and control share acquisition provision discussed below, may deter attempts to cause a change in control of our company (by proxy contest, tender offer or otherwise) and will make more difficult a change in control that is opposed by our board of directors.

Liquidation Rights

Subject to possible prior rights of holders of preferred stock that may be issued in the future, in the event of our liquidation, dissolution or winding up, whether voluntary or involuntary, the holders of our common stock are entitled to receive the remaining assets and funds pro rata, according to the number of shares of common stock held.

Other Provisions

Oklahoma has enacted legislation aimed at regulating takeovers of corporations and restricting specified business combinations with interested shareholders. Under the Oklahoma General Corporation Act, a shareowner who acquires more than 15 percent of the outstanding voting shares of a corporation subject to the statute, but less than 85 percent of such shares, is prohibited from engaging in specified "business combinations" with the corporation for three years after the date that the shareowner became an interested stockholder. This provision does not apply if (1) before the acquisition date the corporation's board of directors has approved either the business combination or the transaction in which the shareowner became an interested shareowner or (2) the corporation's board of directors approves the business combination and at least two-thirds of the outstanding voting stock of the corporation not owned by the interested shareowner vote to authorize the business combination. The term "business combination" encompasses a wide variety of transactions with or caused by an interested shareowner in which the interested shareowner receives or could receive a benefit on other than a pro rata basis with other shareowners, including mergers, specified asset sales, specified issuances of additional shares to the interested shareowner, transactions with the corporation that increase the proportionate interest of the interested shareowner or transactions in which the interested shareowner receives certain other benefits.

Oklahoma law also contains control share acquisition provisions. These provisions generally require the approval of the holders of a majority of the corporation's voting shares held by disinterested shareowners before a person purchasing one-fifth or more of the corporation's voting shares can vote the shares in excess of the one-fifth interest. Similar shareholder approvals are required at one-third and majority thresholds.

The board of directors may allot and issue shares of common stock for such consideration, not less than the par value thereof, as it may from time to time determine. No holder of common stock has the preemptive right to subscribe for or purchase any part of any new or additional issue of stock or securities convertible into stock. Our common stock is not subject to further calls or to assessment by us.

Our common stock is listed on the New York Stock Exchange. Computershare is the Transfer Agent and Registrar for our common stock.

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Long-Term Debt

6 Months Ended

Jun. 30, 2013

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

AtJune 30, 2013, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day.  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)
0.20%	-	0.34%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.21%	-	0.39%	Muskogee Industrial Authority, January 1, 2025	32.4
0.15%	-	0.30%	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, at100 percentof 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.

Issuance of New Long-Term Debt

On May 8, 2013, OG&E issued$250 millionof3.9%senior notes dueMay 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures, general corporate expenses and for working capital purposes. 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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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Automatic Dividend Reinvestment and Stock Purchase Plan [Member]	Jun. 30, 2013 Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, Dividend Reinvestment Plan and Stock Purchase Plan			91,588	198,790
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan	$ 6.9	$ 7.0	$ 3.3	$ 6.4
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan			4,046,198	4,046,198

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.8	$ 0.5	$ 1.2	$ 0.9
Amortization of prior service cost	0.1	0.1	0.1	0.1
Postretirement Benefit Plans:
Amortization of deferred net loss	0.3	0.3	0.6	0.6
Amortization of prior service cost	(0.2)	(0.2)	(0.5)	(0.5)
Deferred commodity contracts hedging gains reclassified in net income	0	0	(0.1)	(1.7)
Deferred commodity contracts hedging losses	0	(0.2)	0	(0.2)
Amortization of deferred interest rate swap hedging losses	$ 0	$ 0	$ 0.1	$ 0.1

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Accounting Pronouncement

6 Months Ended

Jun. 30, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

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

Accounting Pronouncement

In February 2013, the Emerging Issues Task Force issued "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward or Tax Credit Carryforward Exists." The new standard requires entities to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the statement of financial position as a reduction to a deferred tax asset for a net operating loss carryforward or a tax credit carryforward, except as follows. To the extent that a net operating loss carryforward or tax credit carryforward at the reporting date is not available under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, the unrecognized tax benefit would be presented in the statement of financial position as a liability. The new standard is applicable for all entities that have unrecognized tax benefits when a net operating loss carryforward or a tax credit carryforward exists. The new standard is effective for interim and annual reporting periods beginning after December 15, 2013 and does not require any new financial statement disclosures. This new standard may be applied retrospectively or prospectively with early adoption permitted. The Company retrospectively adopted this new standard effective January 1, 2013.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2013

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:

(In millions)	June 30, 2013		December 31, 2012
Regulatory Assets
Current
Crossroads wind farm rider under recovery (A)	$	11.3	$	14.9
Oklahoma demand program rider under recovery (A)	8.4		9.2
Fuel clause under recoveries	1.7		—
Other (A)	8.4		2.9
Total Current Regulatory Assets	$	29.8	$	27.0
Non-Current
Benefit obligations regulatory asset	$	357.0	$	370.6
Income taxes recoverable from customers, net	55.2		54.7
Smart Grid	43.4		42.8
Deferred storm expenses	17.2		12.7
Unamortized loss on reacquired debt	12.4		13.0
Deferred pension expenses	2.4		4.5
Other	14.3		12.3
Total Non-Current Regulatory Assets	$	501.9	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	21.8	$	109.2
Smart Grid rider over recovery (B)	19.4		24.1
Other (B)	5.1		7.8
Total Current Regulatory Liabilities	$	46.3	$	141.1
Non-Current
Accrued removal obligations, net	$	219.7	$	218.2
Pension tracker	12.6		9.2
Deferred pension credits	12.1		17.7
Total Non-Current Regulatory Liabilities	$	244.4	$	245.1

(A) Included in Other Current Assets on theCondensed Consolidated Balance Sheets.

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

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table summarizes changes to the Company's asset retirement obligations during thesixmonths endedJune 30, 2013and2012.

	Six Months Ended
	June 30,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled (A)	(0.4		)	—
Accretion expense	1.1			0.9
Revisions in estimated cash flows (B)	—			26.7
Balance at June 30	$	54.7		$	52.4

(A) As a result of the formation of Enable Midstream Partners on May 1, 2013, the Company has no obligations at June 30, 2013 under OGE Holdings' asset retirement obligations previously disclosed in the Company's 2012 10-K.

(B) Due to changes to OG&E's asset retirement obligations related to its wind farms as a result of changes in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.

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

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to OGE Energy during the sixmonths endedJune 30, 2013. All amounts below are presented net of tax and noncontrolling interest.

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
	Net loss			Prior service cost		Net loss			Prior service cost			Deferred commodity contracts hedging gains			Deferred interest rate swap hedging losses			Noncontrolling interest			Total
Balance at December 31, 2012	$	(49.3	)	$	0.1	$	(15.7	)	$	7.2		$	0.1		$	(0.5	)	$	(9.0	)	$	(49.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9			—		1.0			(0.9		)	(0.1		)	0.1			0.1			1.9
Deconsolidation of Enogex Holdings	2.8			—		1.0			(0.3		)	(0.7		)	—			8.9			(6.1		)
Net current period other comprehensive income (loss)	4.7			—		2.0			(1.2		)	(0.8		)	0.1			9.0			(4.2		)
Balance at June 30, 2013	$	(44.6	)	$	0.1	$	(13.7	)	$	6.0		$	(0.7	)	$	(0.4	)	$	—		$	(53.3	)

Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]

The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the three and sixmonths endedJune 30, 2013.

Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Gains (losses) on cash flow hedges
Commodity contracts	$	—		$	0.2		Cost of goods sold
Interest rate swap	—			(0.2		)	Interest expense
	$	—		$	—		Total before tax
Amortization of defined benefit pension items
Actuarial gains (losses)	$	(1.8	)	$	(3.1	)	(A)
Prior service cost	(0.1		)	(0.1		)	(A)
	(1.9		)	(3.2		)	Total before tax
	(0.9		)	(1.3		)	Tax benefit
	(1.0		)	(1.9		)	Net of tax
	—			(0.1		)	Noncontrolling interest
	$	(1.0	)	$	(1.8	)	Net of tax and noncontrolling interest
Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.8	)	$	(1.6	)	(A)
Prior service cost	0.6			1.4			(A)
	(0.2		)	(0.2		)	Total before tax
	(0.1		)	(0.1		)	Tax benefit
	$	(0.1	)	$	(0.1	)	Net of tax
Total reclassifications for the period	$	(1.1	)	$	(1.9	)	Net of tax and noncontrolling interest

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

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Short-Term Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified				6 Months Ended
	Jun. 30, 2013		Dec. 31, 2012	Jun. 30, 2013 OGE Energy [Member]		Jun. 30, 2013 OG&E [Member]		May 01, 2013 Midstream Partnership [Member]	Jun. 30, 2013 Enogex LLC [Member]
Line of Credit Facility [Line Items]
Short-term debt	$ 478.7		$ 430.9
Line of Credit Facility [Abstract]
Aggregate Commitment	1,150.0			750.0	[1]	400.0	[2]	1,400.0	400.0	[2]
Amount Outstanding	480.8	[3]		478.7	[1],[3]	2.1	[2],[3]
Total	1,150.0	[4]
Weighted Average Interest Rate	0.31%			0.31%	[1],[5]	0.53%	[2],[5]
Maturity				Dec. 13, 2017	[6]	Dec. 13, 2017	[6]
Short Term Borrowing Capacity That Has Regulatory Approval						$ 800
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt						2 years

[1] 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, 2013, there was $478.7 million in outstanding commercial paper borrowings.

[2] 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, 2013, there was $2.1 million supporting letters of credit.

[3] Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2013.

[4] Effective May 1, 2013, Enable Midstream Partners entered into a $1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's $400 million revolving credit facility was terminated.

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

[6] In December 2011, the Company and OG&E entered into unsecured five-year revolving credit agreements to total in the aggregate 1,150.0 million ($750 million for the Company and $400 million for OG&E). Each of the credit facilities contain an option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013, the Company and OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of their credit agreements to December 13, 2017.

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Short-Term Debt and Credit Facilities

6 Months Ended

Jun. 30, 2013

Short-term Debt [Abstract]

Short-Term Debt and Credit Facilities

Short-Term Debt and CreditFacilities

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$478.7 millionand$430.9 millionatJune 30, 2013andDecember 31, 2012, respectively. The following table provides information regarding the Company's revolving credit agreements at June 30, 2013.

	Aggregate			Amount		Weighted-Average
Entity	Commitment			Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0		$	478.7	0.31	%	(E)	December 13, 2017	(F)
OG&E (C)	400.0			2.1		0.53	%	(E)	December 13, 2017	(F)
Total	$	1,150.0	(D)	$	480.8	0.31	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2013.

(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, 2013, there was $478.7 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, 2013, there was $2.1 million supporting letters of credit.

(D) Effective May 1, 2013, Enable Midstream Partnersentered into a$1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's$400 millionrevolving credit facility was terminated.

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

(F) In December 2011,the Company andOG&E entered intounsecured five-year revolving credit agreements to total in the aggregate1,150.0 million ($750 millionfor the Company and$400 millionfor OG&E).Each of thecredit facilitiescontainan option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013,the Company andOG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity oftheircredit agreementsto December 13, 2017.

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 downgradecould 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 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2013 and ending December 31, 2014.

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Derivative Instruments and Hedging Activities, Balance Sheet Presentation Related to Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012 Enogex [Member]		Dec. 31, 2012 Enogex [Member] Designated as Hedging Instrument [Member]	Dec. 31, 2012 Enogex [Member] Designated as Hedging Instrument [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Other Current Assets [Member]	Dec. 31, 2012 Enogex [Member] Not Designated as Hedging Instrument [Member]	Dec. 31, 2012 Enogex [Member] Not Designated as Hedging Instrument [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Current PRM [Member]	Dec. 31, 2012 Enogex [Member] Not Designated as Hedging Instrument [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Other Current Assets [Member]	Dec. 31, 2012 Enogex [Member] Not Designated as Hedging Instrument [Member] Natural gas [Member] Physical [Member] Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	$ 0	$ 5.5	[1]	$ 0	$ 0	$ 5.5	$ 0.1	$ 5.0	$ 0.4
Liabilities		$ 5.5	[1]	$ 0.5	$ 0.5	$ 5.0	$ 0	$ 4.7	$ 0.3

[1] 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, 2012.

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Retirement Plans and Postretirement Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2013		Jun. 30, 2012		Jun. 30, 2013		Jun. 30, 2012
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year	$ 35
Defined Benefit Plan, Contributions by Employer	35
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost (net of unconsolidated affiliates)	6.4		7.6		13.0		15.3
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	4.5		4.5		9.5		9.0
Interest cost	6.8		7.5		13.4		15.0
Expected return on plan assets	(11.9)		(11.5)		(24.2)		(23.0)
Amortization of net loss	7.0		6.0		13.2		11.9
Amortization of unrecognized prior service cost	0.4	[1]	0.5	[1]	0.9	[1]	1.1	[1]
Total net periodic benefit cost	6.8		7.0		12.8		14.0
Less: Amount paid by unconsolidated affiliates	1.0		0		1.0		0
Net periodic benefit cost (net of unconsolidated affiliates)	5.8	[2]	7.0	[2]	11.8	[3]	14.0	[3]
Capitalized Portion of Net Periodic Benefit Cost	1.5		1.6		2.6		3.1
Restoration of Retirement Income Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0.3		0.2		0.6		0.5
Interest cost	0.2		0.2		0.3		0.3
Expected return on plan assets	0		0		0		0
Amortization of net loss	0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost	0	[1]	0.1	[1]	0.1	[1]	0.3	[1]
Total net periodic benefit cost	0.6		0.6		1.2		1.3
Less: Amount paid by unconsolidated affiliates	0		0		0		0
Net periodic benefit cost (net of unconsolidated affiliates)	0.6	[2]	0.6	[2]	1.2	[3]	1.3	[3]
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	1.0		1.1		2.2		2.1
Interest cost	2.6		3.0		5.2		6.0
Expected return on plan assets	(0.7)		(0.7)		(1.3)		(1.5)
Amortization of transition obligation	0		0.7		0		1.4
Amortization of net loss	5.4		5.1		10.7		10.2
Amortization of unrecognized prior service cost	(4.2)	[1]	(4.2)	[1]	(8.3)	[1]	(8.3)	[1]
Total net periodic benefit cost	4.1		5.0		8.5		9.9
Less: Amount paid by unconsolidated affiliates	0.4		0		0.4		0
Net periodic benefit cost (net of unconsolidated affiliates)	3.7	[4]	5.0	[4]	8.1	[5]	9.9	[5]
Capitalized Portion of Net Periodic Benefit Cost	0.8		1.0		1.6		2.0
OKLAHOMA | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements	1.2		2.8		3.1		5.7
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements	$ 0.2		$ 0.4		$ 0.3		$ 0.8

[1] Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

[2] In addition to the $6.4 million and $7.6 million of net periodic benefit cost recognized during the three months ended June 30, 2013 and 2012, respectively, OG&E recognized an increase in pension expense during the three months ended June 30, 2013 and 2012 of $1.2 million and $2.8 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

[3] In addition to the $13.0 million and $15.3 million of net periodic benefit cost recognized during the six months ended June 30, 2013 and 2012, respectively, OG&E recognized an increase in pension expense during the six months ended June 30, 2013 and 2012 of $3.1 million and $5.7 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

[4] In addition to the $3.7 million and $5.0 million of net periodic benefit cost recognized during the three months ended June 30, 2013 and 2012, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended June 30, 2013 and 2012 of $0.2 million and $0.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

[5] In addition to the $8.1 million and $9.9 million of net periodic benefit cost recognized during the six months ended June 30, 2013 and 2012, respectively, OG&E recognized an increase in postretirement medical expense during the six months ended June 30, 2013 and 2012 of $0.3 million and $0.8 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (53.3)		$ (53.3)		$ (49.1)
Amounts reclassified from accumulated other comprehensive income (loss)	(1.0)	(0.7)	(1.9)	(1.5)
Amounts reclassified from accumulated other comprehensive income (loss)			1.9
Deconsolidation of Enogex Holdings	6.1	0	6.1	0
Deconsolidation of Enogex Holdings			(6.1)
Net current period other comprehensive income (loss)			(4.2)
Commodity Contract [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(0.7)		(0.7)		0.1
Amounts reclassified from accumulated other comprehensive income (loss)			(0.1)
Deconsolidation of Enogex Holdings			(0.7)
Net current period other comprehensive income (loss)			(0.8)
Interest Rate Swap [Member]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(0.4)		(0.4)		(0.5)
Amounts reclassified from accumulated other comprehensive income (loss)			0.1
Deconsolidation of Enogex Holdings			0
Net current period other comprehensive income (loss)			0.1
Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax	0		0		(9.0)
Amounts reclassified from accumulated other comprehensive income (loss)			0.1
Deconsolidation of Enogex Holdings			8.9
Net current period other comprehensive income (loss)			9.0
Pension Plans, Defined Benefit [Member] | Defined Benefit Plan Income Loss [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(44.6)		(44.6)		(49.3)
Amounts reclassified from accumulated other comprehensive income (loss)			1.9
Deconsolidation of Enogex Holdings			2.8
Net current period other comprehensive income (loss)			4.7
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	0.1		0.1		0.1
Amounts reclassified from accumulated other comprehensive income (loss)			0
Deconsolidation of Enogex Holdings			0
Net current period other comprehensive income (loss)			0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plan Income Loss [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(13.7)		(13.7)		(15.7)
Amounts reclassified from accumulated other comprehensive income (loss)			1.0
Deconsolidation of Enogex Holdings			1.0
Net current period other comprehensive income (loss)			2.0
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	6.0		6.0		7.2
Amounts reclassified from accumulated other comprehensive income (loss)			(0.9)
Deconsolidation of Enogex Holdings			(0.3)
Net current period other comprehensive income (loss)			$ (1.2)

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Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Tables)

2 Months Ended

Jun. 30, 2013

Summarized Financial Information of Equity Method Investment [Line Items]

Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]

	Two Months Ended
Income Statement	June 30, 2013
	(In millions)
Operating revenues	$	502.0
Gross margin	207.4
Operating expenses	132.4
Net income	65.1

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Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Tables)

Jun. 30, 2013

Summarized Financial Information of Equity Method Investment [Line Items]

Summarized Balance Sheet Financial Information, Equity Method Investment [Table Text Block]

As Enable Midstream Partners began operations on May 1, 2013, summarized unaudited financial information for 100 percent of Enable Midstream Partners is presented below at June 30, 2013 (at historical cost) and for the two months ended June 30, 2013. Fair value information for Enable Midstream Partners' information below is not currently available; however, OGE Holdings expects these fair value amounts to be available by the end of the third quarter of 2013.

Balance Sheet	June 30, 2013
	(In millions)
Current assets	$	393.9
Non-Current assets	8,209.2
Current liabilities	379.6
Non-Current liabilities	2,249.1

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Fair Value Measurements Carrying and Fair Value Amounts (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 2,154.3	$ 1,904.2
Long-Term Debt, Fair Value	2,465.6	2,401.6
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
OG&E Tinker Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	10.6	10.7
Long-Term Debt, Fair Value	10.7	10.0
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	99.9	99.9
Long-Term Debt, Fair Value	104.5	106.3
Enogex LLC Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount		448.4	[1]
Long-Term Debt, Fair Value		493.4	[1]
Enogex LLC Term Loan [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount		250.0	[1]
Long-Term Debt, Fair Value		$ 250.0	[1]

[1] As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company's consolidated financial statements do not include any obligations for the Enogex LLC Senior Notes and Enogex LLC Term Loan as of May 1, 2013.

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Retirement Plans and Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2013

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												Restoration of Retirement Income Plan
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)			2013 (B)		2012 (B)		2013 (C)		2012 (C)
Service cost	$	4.5		$	4.5		$	9.5		$	9.0		$	0.3	$	0.2	$	0.6	$	0.5
Interest cost	6.8			7.5			13.4			15.0			0.2		0.2		0.3		0.3
Expected return on plan assets	(11.9		)	(11.5		)	(24.2		)	(23.0		)	—		—		—		—
Amortization of net loss	7.0			6.0			13.2			11.9			0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost (A)	0.4			0.5			0.9			1.1			—		0.1		0.1		0.3
Total net periodic benefit cost	6.8			7.0			12.8			14.0			0.6		0.6		1.2		1.3
Less: Amount paid by unconsolidated affiliates	1.0			—			1.0			—			—		—		—		—
Net periodic benefit cost (net of unconsolidated affiliates)	$	5.8		$	7.0		$	11.8		$	14.0		$	0.6	$	0.6	$	1.2	$	1.3

(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B) In addition to the$6.4 millionand$7.6 millionof net periodic benefit cost recognizedduring thethreemonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in pension expense during thethreemonths endedJune 30, 2013and2012of$1.2 millionand$2.8 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$13.0 millionand$15.3 millionof net periodic benefit cost recognizedduring thesixmonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in pension expense during thesixmonths endedJune 30, 2013and2012of$3.1 millionand$5.7 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)
Service cost	$	1.0		$	1.1		$	2.2		$	2.1
Interest cost	2.6			3.0			5.2			6.0
Expected return on plan assets	(0.7		)	(0.7		)	(1.3		)	(1.5		)
Amortization of transition obligation	—			0.7			—			1.4
Amortization of net loss	5.4			5.1			10.7			10.2
Amortization of unrecognized prior service cost (A)	(4.2		)	(4.2		)	(8.3		)	(8.3		)
Total net periodic benefit cost	4.1			5.0			8.5			9.9
Less: Amount paid by unconsolidated affiliates	0.4			—			0.4			—
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.7		$	5.0		$	8.1		$	9.9

(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B) In addition to the$3.7 millionand$5.0 millionof net periodic benefit cost recognizedduring thethreemonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthethreemonths endedJune 30, 2013and2012of$0.2 millionand$0.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$8.1 millionand$9.9 millionof net periodic benefit cost recognizedduring thesixmonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthesixmonths endedJune 30, 2013and2012of$0.3 millionand$0.8 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

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Summary of Significant Accounting Policies Forward Stock Split (Details) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Class of Stock [Line Items]
Common Stock, Shares Authorized	450	225

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Derivative Instruments and Hedging Activities, Income Statement Presentation Related to Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified		3 Months Ended	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	3 Months Ended	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012 Enogex [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Enogex [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Enogex [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Enogex [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Enogex [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Enogex [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Enogex [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Enogex [Member] Natural gas [Member] Fixed Swaps/Futures [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Enogex [Member] Sales [Member] Natural gas [Member] Physical [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Enogex [Member] Sales [Member] Natural gas [Member] Physical [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 OGE Energy Corp. [Member] Interest Rate Swap [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 OGE Energy Corp. [Member] Interest Rate Swap [Member] Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Other Comprehensive Income		$ (0.5)	$ (0.2)			$ (0.5)	$ (0.2)					$ 0	$ 0
Amount Reclassifed from Accumulated Other Comprehensive Income (Loss) into Income		(0.1)	5.0			0	5.2					(0.1)	(0.2)
Amount Recognized in Income		0	0	(3.1)	(5.1)	0	0	0.6	1.0	(3.7)	(6.1)	0	0
Derivative Instruments With Credit Risk Related Contingent Features	$ 0

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Common Equity (Tables)

6 Months Ended

Jun. 30, 2013

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)	2013		2012		2013		2012
Net Income Attributable to OGE Energy	$	91.7	$	93.9	$	114.8	$	131.0
Average Common Shares Outstanding
Basic average common shares outstanding	198.3		197.2		198.0		196.8
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.1		0.6		1.1		0.8
Diluted average common shares outstanding	199.4		197.8		199.1		197.6
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.46	$	0.48	$	0.58	$	0.66
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.46	$	0.47	$	0.58	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 393.9
Non-Current assets	8,209.2
Current liabilities	379.6
Non-Current liabilities	$ 2,249.1

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Investment in Unconsolidated Affiliates (Tables)

2 Months Ended

Jun. 30, 2013

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

As OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013, related party transactions between the Company and its affiliate, Enable Midstream Partners, after May 1, 2013, which were previously eliminated in consolidation, are discussed below.

	Two Months Ended
	June 30,
(In millions)	2013
Operating Revenues:
Electricity to power electric compression assets	$	1.3
Cost of Goods Sold:
Natural gas transportation services	$	5.8
Natural gas storage services	2.3
Natural gas purchases (A)	2.5

(A) AtJune 30, 2013, there was $1.2 millionof natural gas purchases recorded for these activities.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 0	$ 1.8
Accounts receivable, less reserve of $1.5 and $2.6, respectively	186.7	295.3
Accounts receivable - unconsolidated affiliates	9.1	0
Accrued unbilled revenues	83.2	57.4
Income taxes receivable	10.7	7.2
Fuel inventories	98.7	93.3
Materials and supplies, at average cost	81.5	80.9
Deferred income taxes	97.7	187.7
Fuel clause under recoveries	1.7	0
Assets held for sale	0	25.5
Other	37.7	45.1
Total current assets	607.0	794.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,267.2	0
Other	55.9	52.2
Total other property and investments	1,323.1	52.2
PROPERTY, PLANT AND EQUIPMENT
In service	8,849.7	11,504.4
Construction work in progress	421.4	387.5
Total property, plant and equipment	9,271.1	11,891.9
Less accumulated depreciation	2,888.2	3,547.1
Net property, plant and equipment	6,382.9	8,344.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	501.9	510.6
Intangible assets, net	0	127.4
Goodwill	0	39.4
Other	33.6	53.6
Total deferred charges and other assets	535.5	731.0
TOTAL ASSETS	8,848.5	9,922.2
CURRENT LIABILITIES
Short-term debt	478.7	430.9
Accounts payable	219.6	396.7
Dividends payable	41.4	41.2
Customer deposits	69.7	70.3
Accrued taxes	40.3	48.1
Accrued interest	45.1	55.0
Accrued compensation	39.5	55.2
Fuel clause over recoveries	21.8	109.2
Other	60.5	69.8
Total current liabilities	1,016.6	1,276.4
LONG-TERM DEBT	2,400.2	2,848.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	366.9	399.8
Deferred income taxes	1,916.2	1,948.8
Deferred investment tax credits	2.9	3.9
Regulatory liabilities	244.4	245.1
Deferred revenues	0.2	37.7
Other	89.8	89.5
Total deferred credits and other liabilities	2,620.4	2,724.8
Total liabilities	6,037.2	6,849.8
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,059.7	1,047.4
Retained earnings	1,804.9	1,772.4
Accumulated other comprehensive loss, net of tax	(53.3)	(49.1)
Treasury stock, at cost	0	(3.5)
Total OGE Energy stockholders' equity	2,811.3	2,767.2
Noncontrolling interests	0	305.2
Total stockholders' equity	2,811.3	3,072.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 8,848.5	$ 9,922.2

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Unaudited) (USD $) In Millions, unless otherwise specified	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest	Treasury Stock
Balance at Dec. 31, 2011	$ 2,819.3	$ 1.0	$ 1,034.3	$ 1,574.8	$ (40.6)	$ 256.0	$ (6.2)
Changes in Stockholders' Equity
Net income	149.1	0	0	131.0	0	18.1	0
Other comprehensive income (loss), net of tax	(1.8)	0	0	0	(0.9)	(0.9)	0
Dividends declared on common stock	(77.4)	0	0	(77.4)	0	0	0
Issuance of common stock	7.0	0	7.0	0	0	0	0
Stock-based compensation and other	(11.0)	0	(14.1)	0	0	(3.0)	6.1
Contributions from noncontrolling interest partners	1.0	0	0	0	0	1.0	0
Distributions to noncontrolling interest partners	(8.0)	0	0	0	0	(8.0)	0
Deconsolidation of Enogex Holdings	0
Balance at Jun. 30, 2012	2,878.2	1.0	1,027.2	1,628.4	(41.5)	263.2	(0.1)
Balance at Dec. 31, 2012	3,072.4	1.0	1,046.4	1,772.4	(49.1)	305.2	(3.5)
Changes in Stockholders' Equity
Net income	121.0	0	0	114.8	0	6.2	0
Other comprehensive income (loss), net of tax	2.0	0	0	0	1.9	0.1	0
Dividends declared on common stock	(82.8)	0	0	(82.8)	0	0	0
Issuance of common stock	6.9	0	6.9	0	0	0	0
Stock-based compensation and other	(5.7)	0	(8.4)	0	0	(0.8)	3.5
Contributions from noncontrolling interest partners	107.0	0	22.5	0	0	84.5	0
Distributions to noncontrolling interest partners	(2.5)	0	0	0	0	(2.5)	0
Deconsolidation of Enogex Holdings	6.1
Deconsolidation of Enogex Holdings	(398.3)	0	0	0.5	(6.1)	(392.7)	0
Deferred income taxes attributable to contributions from noncontrolling interest partners	(8.7)	0	(8.7)	0	0	0	0
2-for-1 forward stock split	0	1.0	(1.0)	0	0	0	0
Balance at Jun. 30, 2013	$ 2,811.3	$ 2.0	$ 1,057.7	$ 1,804.9	$ (53.3)	$ 0	$ 0

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Investment in Unconsolidated Affiliates

6 Months Ended

Jun. 30, 2013

OGE Energy Midstream Partnership with CenterPoint Energy Inc. [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Investment in Unconsolidated Affiliates and Related Party Transactions

On March 14, 2013,OGE Energy entered into a Master Formation Agreement withthe ArcLight groupand CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight groupand CenterPoint Energy, Inc., agreed to form Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPointthat will initially be structured as a private limited partnership. This transaction closed on May 1, 2013.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributed100 percentof the equity interests inEnogex LLCto Enable Midstream Partners. Enogex LLC is a provider of integrated natural gas midstream services. Enogex LLC is engaged in the business of gathering, processing, transporting and storing natural gas.  Most of Enogex LLC's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. CenterPoint Energy Field Services, LLC, a Delaware limited liability company that provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States and wholly owned subsidiary of CenterPoint, was converted into a Delaware limited partnership that became Enable Midstream Partners. CenterPoint contributed to Enable Midstream Partners its equity interests in each of (i) CenterPoint Energy Gas Transmission Company, LLC, a Delaware limited liability company that is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas, (ii) MRT, a Delaware limited liability company that is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Illinois and Missouri and (iii) certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute a24.95 percentinterest in Southeast Supply Header, LLC, a Delaware limited liability company. CenterPoint indirectly owned a 50 percent interest in Southeast Supply Header, LLC, which owns a 1.0 billion cubic feet per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama.

Immediately prior to closing, on May 1, 2013, the ArcLight group contributed $107.0 million and OGE Energy contributed $9.1 million to Enogex LLC in order to pay down short-term debt. At June 30, 2013, OGE Energy holds 28.5 percent of the limited partners interests in Enable Midstream Partners.

CenterPoint has certain put rights, and Enable Midstream Partners has certain call rights, exercisable with respect to any interest in Southeast Supply Header, LLC retained by CenterPoint following the formation of Enable Midstream Partners, under which CenterPoint would contribute to Enable Midstream Partners CenterPoint's retained interest in Southeast Supply Header, LLC at a price equal to the fair market value of such interest at the time the put right or call right is exercised. If CenterPoint were to exercise such put right or Enable Midstream Partners were to exercise such call right, CenterPoint's retained interest in Southeast Supply Header, LLC would be contributed to Enable Midstream Partners in exchange for consideration consisting of a specified number of limited partnership units and, subject to certain restrictions, a cash payment, payable either from CenterPoint to Enable Midstream Partners or from Enable Midstream Partners to CenterPoint, in an amount such that the total consideration exchanged is equal in value to the fair market value of the contributed interest in Southeast Supply Header, LLC.

The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have50 percentof the management rights. CenterPoint and OGE Energy also own a 40 percent and 60 percent interest, respectively, in any incentive distribution rights to be held by the general partner of Enable Midstream Partners following an initial public offering of Enable Midstream Partners. In addition, for a period of time, the ArcLight group will have certain protective rights and approval rights over certain material activities of Enable Midstream Partners, including material increases in capital expenditures and certain equity issuances, entering into transactions with related parties and acquiring, pledging or disposing of certain material assets. The general partner of Enable Midstream Partners will initially be governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy, Inc. and OGE Energy. Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energydeconsolidated its interest in Enogex Holdings LLC andbegan accounting for its interest in Enable Midstream Partners using the equity method of accounting.

Pursuant to a Registration Rights Agreement dated as of May 1, 2013, OGE Energy and CenterPoint Energy, Inc. agreed to initiate the process for the sale of an equity interest in Enable Midstream Partners in an initial public offering. Enable Midstream Partners has agreed to file a registration statement for the initial public offering no later than May 1, 2014 and, subject to limited exceptions, consummate the initial public offering within 180 days of the filing of the registration statement. The Company currently expects that Enable Midstream Partners will file a registration statement during the fourth quarter of 2013. The initial public offering is subject to market conditions and OGE Energy can give no assurances that the initial public offering will be consummated.

Effective May 1, 2013, Enable Midstream Partnersentered into a$1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's$400 millionrevolving credit facility was terminated.

Subject to the exceptions provided below, pursuant to the terms of an Omnibus Agreement dated as of May 1, 2013 among OGE Energy, the ArcLight group and CenterPoint Energy, Inc., each of OGE Energy and CenterPoint Energy, Inc. will be required to hold or otherwise conduct all of its respective Midstream Operations (as defined below) located within the United States in Enable Midstream Partners. This restriction will cease to apply to both OGE Energy and CenterPoint Energy, Inc. as soon as either OGE Energy or CenterPoint Energy, Inc. ceases to hold (i) any interest in the general partner of Enable Midstream Partners or (ii) at least 20 percent of the limited partner interests of Enable Midstream Partners. "Midstream Operations" generally means, subject to certain exceptions, the gathering, compression, treatment, processing, blending, transportation, storage, isomerization and fractionation of crude oil and natural gas, its associated production water and enhanced recovery materials such as carbon dioxide, and its respective constituents and the following products: methane, NGLs (Y-grade, ethane, propane, normal butane, isobutane and natural gasoline), condensate, and refined products and distillates (gasoline, refined product blendstocks, olefins, naphtha, aviation fuels, diesel, heating oil, kerosene, jet fuels, fuel oil, residual fuel oil, heavy oil, bunker fuel, cokes, and asphalts), to the extent such activities are located within the United States.

In addition, if OGE Energy or CenterPoint Energy, Inc. acquires any assets or equity of any person engaged in Midstream Operations with a value in excess of $50 million (or $100 million in the aggregate with such party's other acquired Midstream Operations that have not been offered to Enable Midstream Partners), the acquiring party will be required to offer Enable Midstream Partners the opportunity to acquire such assets or equity for such value; provided, that the acquiring party will not be obligated to offer any such assets or equity to Enable Midstream Partners if the acquiring party intends to cease using them in Midstream Operations within 12 months. If Enable Midstream Partners does not exercise its option, then the acquiring party will be free to retain and operate such Midstream Operations; provided, however, that if the fair market value of such Midstream Operations is greater than 66 2/3 percent of the fair market value of all of the assets being acquired in such transaction, then the acquiring party will be required to dispose of such Midstream Operations within 24 months.

As long as the ArcLight group has certain protective rights, the ArcLight group will be prohibited from pursuing any transaction independently from Enable Midstream Partners (i) if the ArcLight group's consent is required for Enable Midstream Partners to pursue such transaction and (ii) the ArcLight group affirmatively votes not to consent to such transaction.

On May 1, 2013, OGE Energy, OGE Holdings and Enable Midstream Partners entered into a Seconding Agreement. During the term of the Seconding Agreement, OGE Holdings' employees will continue to perform services for Enable Midstream Partners and its subsidiaries.

Related Party Transactions

As OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013, operating costs charged between the Company and its affiliate, Enable Midstream Partners, after May 1, 2013, which were previously eliminated in consolidation, are discussed below.

OGE Energy charged operating costs to the Enogex Holdings/Enable Midstream Partners of$7.9 million and $14.6 millionduring thethree and sixmonths endedJune 30, 2013, respectively. OGE Energy charges operating costs to its subsidiaries and unconsolidated affiliates based on several factors. Operating costs directly related to specific subsidiaries and unconsolidated affiliates are assigned to those subsidiaries and unconsolidated affiliates.  Where more than one subsidiary or unconsolidated affiliate benefits from certain expenditures, the costs are shared between those subsidiaries and unconsolidated affiliates receiving the benefits.  Operating costs incurred for the benefit of all subsidiaries and unconsolidated affiliates are allocated among the subsidiaries and unconsolidated affiliates, either as overhead based primarily on labor costs or using the "Distrigas" method.  The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.  OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff.  OGE Energy believes this method provides a reasonable basis for allocating common expenses.

As OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013, related party transactions between the Company and its affiliate, Enable Midstream Partners, after May 1, 2013, which were previously eliminated in consolidation, are discussed below.

	Two Months Ended
	June 30,
(In millions)	2013
Operating Revenues:
Electricity to power electric compression assets	$	1.3
Cost of Goods Sold:
Natural gas transportation services	$	5.8
Natural gas storage services	2.3
Natural gas purchases (A)	2.5

(A) AtJune 30, 2013, there was $1.2 millionof natural gas purchases recorded for these activities.

Summarized Financial Information of Enable Midstream Partners

As Enable Midstream Partners began operations on May 1, 2013, summarized unaudited financial information for 100 percent of Enable Midstream Partners is presented below at June 30, 2013 (at historical cost) and for the two months ended June 30, 2013. Fair value information for Enable Midstream Partners' information below is not currently available; however, OGE Holdings expects these fair value amounts to be available by the end of the third quarter of 2013.

Balance Sheet	June 30, 2013
	(In millions)
Current assets	$	393.9
Non-Current assets	8,209.2
Current liabilities	379.6
Non-Current liabilities	2,249.1

	Two Months Ended
Income Statement	June 30, 2013
	(In millions)
Operating revenues	$	502.0
Gross margin	207.4
Operating expenses	132.4
Net income	65.1

Enable Midstream Partners concluded that the formation of Enable Midstream Partners was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes.  Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex Holdings' assets, liabilities and equity will accordingly be adjusted to estimated fair value as of May 1, 2013.  Determining the fair value of certain assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions.  Enable Midstream Partners is using appraisers to assist in the determination of fair value of certain assets.  Enable Midstream Partners' valuation is expected to be finalized in the third quarter of 2013.  OGE Energy does not expect that its estimated equity in earnings of Enable Midstream Partners in the second quarter of 2013 will be materially different as a result of the fair value determination.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2013

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 two business segments:  (i) electric utility and (ii) natural gas midstream operations. For a discussion of the change in the Company’s business segments due to the formation of Enable Midstream Partners, see Note 12. For periods prior to May 1, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements. All significant intercompany transactions have been eliminated in consolidation.

Effective May 1, 2013,OGE Energy, the ArcLight group and CenterPoint Energy, Inc., formed Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPoint. In the formation transaction, OGE Energy and ArcLight contributed Enogex LLC to Enable Midstream Partners andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.The Company determined that its contribution of Enogex LLC to Enable Midstream Partners met the requirements of being in substance real estate and was recorded at historical cost.The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have50 percentof the management rights.Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energybegan accounting for its interest in Enable Midstream Partners using the equity method of accounting. Effective July 30, 2013, the name of Enogex Holdings was changed to Enable Intrastate Holdings II and the name of Enogex LLC was changed to Enable Oklahoma Intrastate Transmission, LLC.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations areconducted through OG&E and aresubject 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.

As discussed below, the Company completed a 2-for-1 stock split of the Company's common stock effective July 1, 2013. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

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 atJune 30, 2013andDecember 31, 2012, the results of its operations for the threeandsixmonths endedJune 30, 2013and2012and the results of its cash flows for thesixmonths endedJune 30, 2013and2012, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company'soperating results for the threeandsixmonths endedJune 30, 2013are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2013or 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 2012Form 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:

(In millions)	June 30, 2013		December 31, 2012
Regulatory Assets
Current
Crossroads wind farm rider under recovery (A)	$	11.3	$	14.9
Oklahoma demand program rider under recovery (A)	8.4		9.2
Fuel clause under recoveries	1.7		—
Other (A)	8.4		2.9
Total Current Regulatory Assets	$	29.8	$	27.0
Non-Current
Benefit obligations regulatory asset	$	357.0	$	370.6
Income taxes recoverable from customers, net	55.2		54.7
Smart Grid	43.4		42.8
Deferred storm expenses	17.2		12.7
Unamortized loss on reacquired debt	12.4		13.0
Deferred pension expenses	2.4		4.5
Other	14.3		12.3
Total Non-Current Regulatory Assets	$	501.9	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	21.8	$	109.2
Smart Grid rider over recovery (B)	19.4		24.1
Other (B)	5.1		7.8
Total Current Regulatory Liabilities	$	46.3	$	141.1
Non-Current
Accrued removal obligations, net	$	219.7	$	218.2
Pension tracker	12.6		9.2
Deferred pension credits	12.1		17.7
Total Non-Current Regulatory Liabilities	$	244.4	$	245.1

(A) Included in Other Current Assets on theCondensed Consolidated Balance Sheets.

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

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 OG&E 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, which could have significant financial effects.

Use of Estimates

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 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 for all Company segments includes the determination of Pension Plan assumptions,impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas midstream operations segment, the most significant judgment is also exercised in the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill and equity method investments.

Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable Midstream Partners is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable Midstream Partners since it does not have the power to direct the activities of Enable Midstream Partners that are considered most significant to the economic performance of Enable Midstream Partners. As discussed above, OGE Energy accounts for the investment in Enable Midstream Partners using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income. OGE Energy's maximum exposure to loss related to Enable Midstream Partners is limited to OGE Energy's equity investment in Enable Midstream Partners as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2013. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during thesixmonths endedJune 30, 2013and2012.

	Six Months Ended
	June 30,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled (A)	(0.4		)	—
Accretion expense	1.1			0.9
Revisions in estimated cash flows (B)	—			26.7
Balance at June 30	$	54.7		$	52.4

(A) As a result of the formation of Enable Midstream Partners on May 1, 2013, the Company has no obligations at June 30, 2013 under OGE Holdings' asset retirement obligations previously disclosed in the Company's 2012 10-K.

(B) Due to changes to OG&E's asset retirement obligations related to its wind farms as a result of changes in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to OGE Energy during the sixmonths endedJune 30, 2013. All amounts below are presented net of tax and noncontrolling interest.

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
	Net loss			Prior service cost		Net loss			Prior service cost			Deferred commodity contracts hedging gains			Deferred interest rate swap hedging losses			Noncontrolling interest			Total
Balance at December 31, 2012	$	(49.3	)	$	0.1	$	(15.7	)	$	7.2		$	0.1		$	(0.5	)	$	(9.0	)	$	(49.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9			—		1.0			(0.9		)	(0.1		)	0.1			0.1			1.9
Deconsolidation of Enogex Holdings	2.8			—		1.0			(0.3		)	(0.7		)	—			8.9			(6.1		)
Net current period other comprehensive income (loss)	4.7			—		2.0			(1.2		)	(0.8		)	0.1			9.0			(4.2		)
Balance at June 30, 2013	$	(44.6	)	$	0.1	$	(13.7	)	$	6.0		$	(0.7	)	$	(0.4	)	$	—		$	(53.3	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the three and sixmonths endedJune 30, 2013.

Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Loss						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Gains (losses) on cash flow hedges
Commodity contracts	$	—		$	0.2		Cost of goods sold
Interest rate swap	—			(0.2		)	Interest expense
	$	—		$	—		Total before tax
Amortization of defined benefit pension items
Actuarial gains (losses)	$	(1.8	)	$	(3.1	)	(A)
Prior service cost	(0.1		)	(0.1		)	(A)
	(1.9		)	(3.2		)	Total before tax
	(0.9		)	(1.3		)	Tax benefit
	(1.0		)	(1.9		)	Net of tax
	—			(0.1		)	Noncontrolling interest
	$	(1.0	)	$	(1.8	)	Net of tax and noncontrolling interest
Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.8	)	$	(1.6	)	(A)
Prior service cost	0.6			1.4			(A)
	(0.2		)	(0.2		)	Total before tax
	(0.1		)	(0.1		)	Tax benefit
	$	(0.1	)	$	(0.1	)	Net of tax
Total reclassifications for the period	$	(1.1	)	$	(1.9	)	Net of tax and noncontrolling interest

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Forward Stock Split

On May 16, 2013, the Company's Board of Directors approved a 2-for-1 forward stock split of the Company's common stock, effective July 1, 2013, which entitled each shareholder of record to receive two shares for every one share of Company stock owned by the shareholder.  In connection with the stock split and as included as Exhibit 3.01 herein, an amendment to the Company's Articles of Incorporation was approved on May 16, 2013 which increased the number of authorized shares of common stock from225 millionto450 million. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Reclassifications

As discussed in Note 12, the formernatural gas transportation and storagesegment andnatural gas gathering and processingsegment have been combined into thenatural gas midstream operationssegment and have been restated for all prior periods presented.Effective May 1, 2013,the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.

As discussed above, as a result of the stock split effective July 1, 2013, all share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

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Investment in Unconsolidated Affiliates (Details) (USD $) In Millions, unless otherwise specified									8 Months Ended
	Jun. 30, 2013	May 01, 2013	Jun. 30, 2013 Enogex LLC [Member]		May 01, 2013 Enogex LLC [Member]	May 01, 2013 Southeast Supply Header, LLC [Member]	May 01, 2013 ArcLight group [Member]	May 01, 2013 OGE Holdings [Member]	Dec. 31, 2013 OGE Energy [Member]	May 01, 2013 OGE Energy [Member]	May 01, 2013 Midstream Partnership [Member]	May 01, 2013 CenterPoint [Member]
Value of Midstream Operations Assets or Equity Acquired		$ 50
Percentage of Enogex LLC Contributed					100.00%
Percentage of Subsidiary Contributed						24.95%
Percentage Share of Management Rights										50.00%		50.00%
Contributions to Pay Down Short-Term Debt							107.0	9.1
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest									28.50%
Percent of Incentive Distribution Rights										60.00%		40.00%
Line of Credit Facility, Maximum Borrowing Capacity	1,150.0		400.0	[1]							1,400.0
Value of Aggregate Midstream Operations Assets or Equity Acquired by Parties Not Offered in Midstream Partnership		$ 100

[1] 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, 2013, there was $2.1 million supporting letters of credit.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

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

The Company hadnomaterial financial instruments measured at fair value on a recurring basis atJune 30, 2013. The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012 as well as presents the Company's commodity contracts fair value included in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company adopted the Financial Accounting Standards Board accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company posted $0.2 million of collateral at December 31, 2012 which has been included within netting adjustments in the table below. The Company held no collateral at December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company held no Level 3 investments at December 31, 2012.

December 31, 2012
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	5.0		$	5.0		$	—	$	—
Significant other observable inputs (Level 2)	0.5			0.5			3.1		3.8
Total fair value	5.5			5.5			3.1		3.8
Netting adjustments	(5.0		)	(5.2		)	—		—
Total	$	0.5		$	0.3		$	3.1	$	3.8

(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 assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012, 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.

(C) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million at December 31, 2012, 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.

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 at June 30, 2013 and December 31, 2012.

	June 30, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,154.3	$	2,465.6	$	1,904.2	$	2,401.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.6		10.7		10.7		10.0
OGE Energy Senior Notes	99.9		104.5		99.9		106.3
Enogex LLC Senior Notes	(A)		(A)		448.4		493.4
Enogex LLC Term Loan	(A)		(A)		250.0		250.0

(A) As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company's consolidated financial statements do not include any obligations for the Enogex LLC Senior Notes and Enogex LLC Term Loan as of May 1, 2013.

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2013

Long-term Debt, Unclassified [Abstract]

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

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day.  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)
0.20%	-	0.34%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.21%	-	0.39%	Muskogee Industrial Authority, January 1, 2025	32.4
0.15%	-	0.30%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

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Summary of Significant Accounting Policies Asset Retirement Obligation (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013		Jun. 30, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 54.0		$ 24.8
Liabilities settled	(0.4)	[1]	0
Accretion expense	1.1		0.9
Revisions in estimated cash flows	0		26.7	[2]
Balance at June 30	54.7		52.4
OGE Enogex Holdings [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at June 30	$ 0

[1] As a result of the formation of Enable Midstream Partners on May 1, 2013, the Company has no obligations at June 30, 2013 under OGE Holdings' asset retirement obligations previously disclosed in the Company's 2012 10-K.

[2] Due to changes to OG&E's asset retirement obligations related to its wind farms as a result of changes in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.

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Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Debt Instrument [Line Items]
Percent of Principal Amount Subject to Optional Tender	100.00%
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
Redeemable during the next 12 months
Debt Instrument [Line Items]
Long-term debt	$ 135.4
Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Series Minimum	0.20%
Series Maximum	0.34%
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Series Minimum	0.21%
Series Maximum	0.39%
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Series Minimum	0.15%
Series Maximum	0.30%
OG&E [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Long term debt, gross	47.0
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Long term debt, gross	32.4
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Long term debt, gross	56.0
Senior Notes [Member] | OG&E [Member] | Series due May 1, 2043 [Member]
Debt Instrument [Line Items]
Long term debt, gross	$ 250.0
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Date Due	May 01, 2043

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Stock-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit	$ 1.0	$ 1.1	$ 2.1	$ 2.2
Stock-Based Compensation Activity
Number of shares granted	91,390
Cash Received from Exercise of Stock Options	1.2		1.4
Tax Benefit Realized from Exercise of Stock Options	0		0
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	2.6	2.6	5.2	5.1
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	0.1	0.2	0.2	0.4
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	2.7	2.8	5.4	5.5
Less: Amount paid by unconsolidated affiliates	0.6	0	0.6	0
Net compensation expense	2.1	2.8	4.8	5.5
Common Stock
Stock-Based Compensation Activity
Number of shares issued	33,000		549,520
Restricted Stock [Member]
Stock-Based Compensation Activity
Shares Paid for Tax Withholding for Share Based Compensation	5,810		6,474
Treasury Stock [Member]
Stock-Based Compensation Activity
Number of shares issued			125,264
Total Shareholder Return [Member]
Stock-Based Compensation Activity
Number of shares granted	45,596
Fair value of shares granted	$ 25.89
Total Shareholder Return [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	1.9	2.0	3.9	3.8
Performance Units Related to Earnings Per Share [Member]
Stock-Based Compensation Activity
Number of shares granted	45,794
Fair value of shares granted	$ 26.73
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 0.7	$ 0.6	$ 1.3	$ 1.3

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Fair Value Measurements, Fair Value Hierarchy (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Securities Held as Collateral, at Fair Value		$ 0
Collateral Already Posted, Aggregate Fair Value		0.2
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets		0
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0
Gas Imbalance Asset Fair Value Disclosure		3.1	[1],[2]
Gas Imbalance Liability Fair Value Disclosure		3.8	[1],[3]
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		3.1	[1],[2]
Gas Imbalance Liability Fair Value Disclosure		3.8	[1],[3]
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],[2]
Gas Imbalance Liability Fair Value Disclosure		0	[1],[3]
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		3.1	[1],[2]
Gas Imbalance Liability Fair Value Disclosure		3.8	[1],[3]
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],[2]
Gas Imbalance Liability Fair Value Disclosure		0	[1],[3]
Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets		0.5
Commodity Contracts Liabilities		0.3
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		5.5
Commodity Contracts Liabilities		5.5
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		5.0
Commodity Contracts Liabilities		5.0
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		0.5
Commodity Contracts Liabilities		0.5
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		(5.0)
Commodity Contracts Liabilities		(5.2)
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 Under Retained Fuel Due From Shippers		5.9
Fuel Reserves For Over Retained Fuel Due To Shippers		$ 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 assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012, 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.

[3] Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million at December 31, 2012, 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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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Net income	$ 93.0	$ 101.6	$ 121.0	$ 149.1
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.8, $0.5, $1.2 and $0.9, respectively	1.0	0.7	1.9	1.5
Amortization of prior service cost, net of tax of $0.1, $0.1, $0.1 and $0.1, respectively	0	0.1	0	0.1
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.3, $0.3, $0.6 and $0.6, respectively	0.5	0.5	1.0	1.0
Amortization of prior service cost, net of tax of ($0.2), ($0.2), ($0.5) and ($0.5), respectively	(0.4)	(0.4)	(0.9)	(0.9)
Deferred commodity contracts hedging gains reclassified in net income, net of tax of $0, $0, ($0.1) and ($1.7), respectively	0	0	(0.1)	(3.3)
Deferred commodity contracts hedging losses, net of tax of $0, ($0.2), $0 and ($0.2), respectively	0	(0.3)	0	(0.3)
Amortization of deferred interest rate swap hedging losses, net of tax of $0, $0, $0.1 and $0.1, respectively	0	0	0.1	0.1
Other comprehensive income (loss), net of tax	1.1	0.6	2.0	(1.8)
Comprehensive income (loss)	94.1	102.2	123.0	147.3
Less: Comprehensive income attributable to noncontrolling interests	1.3	7.7	6.3	17.2
Less: Deconsolidation of Enogex Holdings	6.1	0	6.1	0
Total comprehensive income attributable to OGE Energy	$ 86.7	$ 94.5	$ 110.6	$ 130.1

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2013

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

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

Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethreeandsixmonths endedJune 30, 2013 and 2012related to the Company's performance units and restricted stock.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Performance units
Total shareholder return	$	1.9	$	2.0	$	3.9	$	3.8
Earnings per share	0.7		0.6		1.3		1.3
Total performance units	2.6		2.6		5.2		5.1
Restricted stock	0.1		0.2		0.2		0.4
Total compensation expense	2.7		2.8		5.4		5.5
Less: Amount paid by unconsolidated affiliates	0.6		—		0.6		—
Net compensation expense	$	2.1	$	2.8	$	4.8	$	5.5
Income tax benefit	$	1.0	$	1.1	$	2.1	$	2.2

The Company has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During thethreeandsixmonths endedJune 30, 2013, there were33,000shares and549,520shares, respectively, of newcommon stock issuedpursuant to the Company's stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. During the sixmonths endedJune 30, 2013, there were 125,264 of treasury stock shares issued. During thethreeandsixmonths endedJune 30, 2013, there were5,810sharesand6,474sharesof restricted stock, respectively, returned to the Company to satisfy tax liabilities. The Company received $1.2 million and $1.4 million during the threeandsixmonths endedJune 30, 2013 related to exercised stock options. The Company did not realize an income tax benefit for the tax deductions from the exercised stock options during the threeandsixmonths endedJune 30, 2013 due to the Company being in a tax net operating loss position in 2013.

As a result of the formation of Enable Midstream Partners on May 1, 2013, 50 percent of OGE Holdings' 2013 performance unit grants that were previously based on earnings before interest, taxes, depreciation and amortization were converted to stock-based compensation. The performance unit grants converted totaled 91,390, which is comprised of 45,596 total shareholder return performance units with a $25.89 grant date fair value and 45,794 earnings per share performance units with a $26.73 grant date fair value. The amount of these performance units were adjusted for the effects of the stock split.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 121.0	$ 149.1
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	167.6	177.1
Impairment of assets	0	0.3
Deferred income taxes and investment tax credits, net	50.7	63.1
Equity in earnings of unconsolidated affiliates	(18.5)	0
Allowance for equity funds used during construction	(2.7)	(3.6)
(Gain) loss on disposition and abandonment of assets	(8.7)	0.7
Gain on insurance proceeds	0	(7.5)
Stock-based compensation	(6.6)	(9.4)
Regulatory assets	3.7	10.3
Regulatory liabilities	(9.8)	(7.6)
Other assets	(0.6)	4.8
Other liabilities	(24.2)	(26.6)
Change in certain current assets and liabilities
Accounts receivable, net	(41.4)	19.9
Accrued unbilled revenues	(25.8)	(25.3)
Income taxes receivable	(3.5)	(8.8)
Fuel, materials and supplies inventories	(20.0)	(3.6)
Fuel clause under recoveries	(1.7)	1.1
Other current assets	(7.4)	(18.5)
Accounts payable	(3.9)	(92.6)
Accounts payable - unconsolidated affiliates	10.5	0
Fuel clause over recoveries	(87.4)	57.7
Other current liabilities	(11.4)	0.9
Net Cash Provided from Operating Activities	79.9	281.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(565.0)	(558.5)
Investment in unconsolidated affiliates	(2.7)	0
Proceeds from insurance	0	7.6
Reimbursement of capital expenditures	0	23.4
Proceeds from sale of assets	35.9	0.6
Net Cash Used in Investing Activities	(531.8)	(526.9)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	247.5	0
Changes in advances with unconsolidated affiliates	126.2	0
Contributions from noncontrolling interest partners	107.0	1.0
Increase in short-term debt	47.8	319.6
Issuance of common stock	6.8	7.0
Payment of long-term debt	(0.1)	0
Distributions to noncontrolling interest partners	(2.5)	(8.0)
Dividends paid on common stock	(82.6)	(77.1)
Net Cash Provided from Financing Activities	450.1	242.5
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1.8)	(2.9)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1.8	4.6
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0	$ 1.7

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Report of Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$ 734.2	$ 855.0	$ 1,635.6	$ 1,695.7
Cost of goods sold	370.6	409.3	923.6	894.6
Gross margin on revenues	363.6	445.7	712.0	801.1
Other operation and maintenance	122.0	153.0	270.0	300.6
Depreciation and amortization	74.4	90.5	166.3	177.1
Impairment of assets	0	0.1	0	0.3
Gain on insurance proceeds	0	0	0	(7.5)
Taxes other than income	23.3	24.8	56.4	55.0
Operating income (loss)	143.9	177.3	219.3	275.6
Equity in earnings of unconsolidated affiliates	18.5	0	18.5	0
Investment in unconsolidated affiliates	1,267.2		1,267.2		0
Total assets	8,848.5	9,351.4	8,848.5	9,351.4	9,922.2
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	574.6	528.0	1,030.1	954.7
Cost of goods sold	247.6	204.6	460.6	400.1
Gross margin on revenues	327.0	323.4	569.5	554.6
Other operation and maintenance	107.0	114.7	212.1	225.3
Depreciation and amortization	62.0	62.7	123.3	122.4
Impairment of assets		0		0
Gain on insurance proceeds				0
Taxes other than income	19.9	18.2	43.1	39.3
Operating income (loss)	138.1	127.8	191.0	167.6
Equity in earnings of unconsolidated affiliates	0		0
Investment in unconsolidated affiliates	0		0
Total assets	7,453.6	6,833.2	7,453.6	6,833.2
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	166.1	344.0	630.4	773.6
Cost of goods sold	129.7	222.6	489.0	527.9
Gross margin on revenues	36.4	121.4	141.4	245.7
Other operation and maintenance	15.7	42.7	60.9	85.0
Depreciation and amortization	9.2	24.3	36.8	47.7
Impairment of assets		0.1		0.3
Gain on insurance proceeds				(7.5)
Taxes other than income	2.5	5.7	10.5	13.0
Operating income (loss)	9.0	48.6	33.2	107.2
Equity in earnings of unconsolidated affiliates	18.5		18.5
Investment in unconsolidated affiliates	1,267.2		1,267.2
Total assets	1,266.8	2,395.3	1,266.8	2,395.3
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	(0.7)	(4.4)	(3.0)	(9.7)
Depreciation and amortization	3.2	3.5	6.2	7.0
Impairment of assets		0		0
Gain on insurance proceeds				0
Taxes other than income	0.9	0.9	2.8	2.7
Operating income (loss)	(3.4)	0	(6.0)	0
Equity in earnings of unconsolidated affiliates	0		0
Investment in unconsolidated affiliates	0		0
Total assets	189.4	331.4	189.4	331.4
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(6.5)	(17.0)	(24.9)	(32.6)
Cost of goods sold	(6.7)	(17.9)	(26.0)	(33.4)
Gross margin on revenues	0.2	0.9	1.1	0.8
Other operation and maintenance	0	0	0	0
Depreciation and amortization	0	0	0	0
Impairment of assets		0		0
Gain on insurance proceeds				0
Taxes other than income	0	0	0	0
Operating income (loss)	0.2	0.9	1.1	0.8
Equity in earnings of unconsolidated affiliates	0		0
Investment in unconsolidated affiliates	0		0
Total assets	$ (61.3)	$ (208.5)	$ (61.3)	$ (208.5)

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
OPERATING REVENUES
Electric Utility operating revenues	$ 574.6	$ 528.0	$ 1,030.1	$ 954.7
Natural Gas Midstream Operations operating revenues (Note 1)	159.6	327.0	605.5	741.0
Total operating revenues	734.2	855.0	1,635.6	1,695.7
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	242.8	192.7	442.2	376.3
Natural Gas Midstream Operations cost of goods sold (Note 1)	127.8	216.6	481.4	518.3
Total cost of goods sold	370.6	409.3	923.6	894.6
Gross margin on revenues	363.6	445.7	712.0	801.1
OPERATING EXPENSES
Other operation and maintenance	122.0	153.0	270.0	300.6
Depreciation and amortization	74.4	90.5	166.3	177.1
Impairment of assets	0	0.1	0	0.3
Gain on insurance proceeds	0	0	0	(7.5)
Taxes other than income	23.3	24.8	56.4	55.0
Total operating expenses	219.7	268.4	492.7	525.5
OPERATING INCOME	143.9	177.3	219.3	275.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates (Note 1)	18.5	0	18.5	0
Allowance for equity funds used during construction	1.5	1.7	2.7	3.6
Other income	4.5	2.5	19.2	10.2
Other expense	(4.2)	(3.6)	(10.7)	(5.5)
Net other income	20.3	0.6	29.7	8.3
INTEREST EXPENSE
Interest on long-term debt	36.0	38.9	75.7	78.1
Allowance for borrowed funds used during construction	(0.7)	(0.9)	(1.4)	(2.0)
Interest on short-term debt and other interest charges	2.0	2.4	4.2	4.4
Interest expense	37.3	40.4	78.5	80.5
INCOME BEFORE TAXES	126.9	137.5	170.5	203.4
INCOME TAX EXPENSE	33.9	35.9	49.5	54.3
NET INCOME	93.0	101.6	121.0	149.1
Less: Net income attributable to noncontrolling interests	1.3	7.7	6.2	18.1
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$ 91.7	$ 93.9	$ 114.8	$ 131.0
BASIC AVERAGE COMMON SHARES OUTSTANDING	198.3	197.2	198.0	196.8
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.4	197.8	199.1	197.6
BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$ 0.46	$ 0.48	$ 0.58	$ 0.66
DILUTED EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$ 0.46	$ 0.47	$ 0.58	$ 0.66
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.20875	$ 0.19625	$ 0.4175	$ 0.3925

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended		3 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 FIN 48 [Member]	Jun. 30, 2013 FIN 48 reserve, net of tax [Member]	Jun. 30, 2013 Federal operating loss [Member]	Jun. 30, 2013 State operating loss [Member]
Income Tax Reconciliation, Tax Contingencies, State and Local		$ 7.8	$ 5.1
Reduction in income tax expense related to the Midstream Partnership	3.9
Increase in income tax expense related to deconsolidation	3.9
Net Operating Loss Carryforwards Utilized				227.0	42.0
Net Operating Loss Carryforwards Utilized, Net of Tax				$ 147.6	$ 39.6

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Derivative Instruments and Hedging Activities (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

Balance Sheet Presentation Related to Derivative Instruments

The Company had no material derivative instruments included in its Condensed Consolidated Balance Sheet at June 30, 2013. The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2012 are as follows:

		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	—	$	0.5
Total		$	—	$	0.5
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.1	$	—
	Other Current Assets	5.0		4.7
Physical Purchases/Sales	Current PRM	0.4		0.3
Total		$	5.5	$	5.0
Total Gross Derivatives (A)		$	5.5	$	5.5

(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, 2012.

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

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for thethreemonths endedJune 30, 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.5	)	$	—		$	—
Interest Rate Swap	—			(0.1		)	—
Total	$	(0.5	)	$	(0.1	)	$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(3.7	)
Natural Gas Financial Futures/Swaps	0.6
Total	$	(3.1	)

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for thesixmonths endedJune 30, 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.2	)	$	5.2		$	—
Interest Rate Swap	—			(0.2		)	—
Total	$	(0.2	)	$	5.0		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(6.1	)
Natural Gas Financial Futures/Swaps	1.0
Total	$	(5.1	)

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

8 Months Ended

Jun. 30, 2013

Dec. 31, 2013

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 two business segments:  (i) electric utility and (ii) natural gas midstream operations. For a discussion of the change in the Company’s business segments due to the formation of Enable Midstream Partners, see Note 12. For periods prior to May 1, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements. All significant intercompany transactions have been eliminated in consolidation.

Effective May 1, 2013,OGE Energy, the ArcLight group and CenterPoint Energy, Inc., formed Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPoint. In the formation transaction, OGE Energy and ArcLight contributed Enogex LLC to Enable Midstream Partners andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.The Company determined that its contribution of Enogex LLC to Enable Midstream Partners met the requirements of being in substance real estate and was recorded at historical cost.The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have50 percentof the management rights.Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energybegan accounting for its interest in Enable Midstream Partners using the equity method of accounting. Effective July 30, 2013, the name of Enogex Holdings was changed to Enable Intrastate Holdings II and the name of Enogex LLC was changed to Enable Oklahoma Intrastate Transmission, LLC.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations areconducted through OG&E and aresubject 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.

As discussed below, the Company completed a 2-for-1 stock split of the Company's common stock effective July 1, 2013. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

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 atJune 30, 2013andDecember 31, 2012, the results of its operations for the threeandsixmonths endedJune 30, 2013and2012and the results of its cash flows for thesixmonths endedJune 30, 2013and2012, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company'soperating results for the threeandsixmonths endedJune 30, 2013are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2013or 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 2012Form 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 OG&E 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, which could have significant financial effects.

Use of Estimates, Policy [Policy Text Block]

Use of Estimates

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 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 for all Company segments includes the determination of Pension Plan assumptions,impairment estimates of long-lived assets (including intangible assets), income taxes, contingency reserves, asset retirement obligations and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas midstream operations segment, the most significant judgment is also exercised in the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill and equity method investments.

Equity Method Investments, Policy [Policy Text Block]

Based on the 50/50 management ownership, with neither company having control,effective May 1, 2013, OGE Energybegan accounting for its interest in Enable Midstream Partners using the equity method of accounting.

Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable Midstream Partners is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable Midstream Partners since it does not have the power to direct the activities of Enable Midstream Partners that are considered most significant to the economic performance of Enable Midstream Partners. As discussed above, OGE Energy accounts for the investment in Enable Midstream Partners using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income. OGE Energy's maximum exposure to loss related to Enable Midstream Partners is limited to OGE Energy's equity investment in Enable Midstream Partners as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2013. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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 is 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 options 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).

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, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets 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 Company's long-term debt is valued at the carrying amount.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 and is classified as Level 2 in the fair value hierarchy except for the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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]

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments are utilized in OGE Holdings' asset management activities.  

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.

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 (Loss) 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 previously designated as cash flow hedges derivatives for OGE Holdings' 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 operations and natural gas transportation and storage operations (operational gas hedges).  The Company also previously designated as cash flow hedges certain derivatives for certain natural gas storage inventory positions.

Income Tax, Policy [Policy Text Block]

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 files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions.

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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Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) (USD $) In Millions, unless otherwise specified	2 Months Ended
	Jun. 30, 2013
Summarized Income Statement of Equity Method Investment [Abstract]
Operating revenues	$ 502.0
Gross margin	207.4
Operating expenses	132.4
Net income	$ 65.1

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Common Equity Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Equity [Abstract]
Net Income Attributable to OGE Energy	$ 91.7	$ 93.9	$ 114.8	$ 131.0
Basic Average Common Shares Outstanding	198.3	197.2	198.0	196.8
Contingently Issuable Shares (Performance Units)	1.1	0.6	1.1	0.8
Diluted Average Common Shares Outstanding	199.4	197.8	199.1	197.6
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.46	$ 0.48	$ 0.58	$ 0.66
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.46	$ 0.47	$ 0.58	$ 0.66
Anti-dilutive shares excluded from earnings per share calculation	0	0	0	0

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) Reclassifications out of AOCI (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Amounts Reclassified from Accumulated Other Comprehensive Loss, Total Before Tax	$ 0		$ 0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss), Hedging, Tax	0	0	(0.1)	(1.7)
Amounts Reclassified from Accumulated Other Comprehensive Income Loss, Hedging, Net of Tax	0	0	0.1	3.3
Amounts Reclassified from Accumulated Other Comprehensive Loss, Net of Tax and Noncontrolling Interest	(1.1)		(1.9)
Commodity Contract [Member]
Amounts Reclassified from Accumulated Other Comprehensive Loss, Total Before Tax	0		0.2
Interest Rate Swap [Member]
Amounts Reclassified from Accumulated Other Comprehensive Loss, Total Before Tax	0		(0.2)
Pension Plan [Member]
Amounts Reclassified from Accumulated Other Comprehensive Loss, Gain (Loss)	(1.8)		(3.1)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Prior Service Cost	(0.1)		(0.1)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Total Before Tax	(1.9)		(3.2)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Tax Benefit	(0.9)		(1.3)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Net of Tax	(1.0)		(1.9)
Amount Reclassified from Accumulated Other Comprehensive Loss, Noncontrolling Interest	0		(0.1)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Net of Tax and Noncontrolling Interest	(1.0)		(1.8)
Postretirement Benefit Plan [Member]
Amounts Reclassified from Accumulated Other Comprehensive Loss, Gain (Loss)	(0.8)		(1.6)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Prior Service Cost	0.6		1.4
Amounts Reclassified from Accumulated Other Comprehensive Loss, Total Before Tax	(0.2)		(0.2)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Tax Benefit	(0.1)		(0.1)
Amounts Reclassified from Accumulated Other Comprehensive Loss, Net of Tax	$ (0.1)		$ (0.1)

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Report of Business Segments (Tables)

6 Months Ended

Jun. 30, 2013

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 during the threemonths endedJune 30, 2013 and 2012.

Three Months Ended June 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	574.6	$	166.1	$	—		$	(6.5	)	$	734.2
Cost of goods sold	247.6		129.7		—			(6.7		)	370.6
Gross margin on revenues	327.0		36.4		—			0.2			363.6
Other operation and maintenance	107.0		15.7		(0.7		)	—			122.0
Depreciation and amortization	62.0		9.2		3.2			—			74.4
Taxes other than income	19.9		2.5		0.9			—			23.3
Operating income (loss)	$	138.1	$	9.0	$	(3.4	)	$	0.2		$	143.9
Equity in earnings of unconsolidated affiliates	$	—	$	18.5	$	—		$	—		$	18.5
Investment in unconsolidated affiliates	$	—	$	1,267.2	$	—		$	—		$	1,267.2
Total assets	$	7,453.6	$	1,266.8	$	189.4		$	(61.3	)	$	8,848.5

Three Months Ended June 30, 2012	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	528.0	$	344.0	$	—		$	(17.0	)	$	855.0
Cost of goods sold	204.6		222.6		—			(17.9		)	409.3
Gross margin on revenues	323.4		121.4		—			0.9			445.7
Other operation and maintenance	114.7		42.7		(4.4		)	—			153.0
Depreciation and amortization	62.7		24.3		3.5			—			90.5
Impairment of assets	—		0.1		—			—			0.1
Taxes other than income	18.2		5.7		0.9			—			24.8
Operating income (loss)	$	127.8	$	48.6	$	—		$	0.9		$	177.3
Total assets	$	6,833.2	$	2,395.3	$	331.4		$	(208.5	)	$	9,351.4

Six Months Ended June 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.1	$	630.4	$	—		$	(24.9	)	$	1,635.6
Cost of goods sold	460.6		489.0		—			(26.0		)	923.6
Gross margin on revenues	569.5		141.4		—			1.1			712.0
Other operation and maintenance	212.1		60.9		(3.0		)	—			270.0
Depreciation and amortization	123.3		36.8		6.2			—			166.3
Taxes other than income	43.1		10.5		2.8			—			56.4
Operating income (loss)	$	191.0	$	33.2	$	(6.0	)	$	1.1		$	219.3
Equity in earnings of unconsolidated affiliates	$	—	$	18.5	$	—		$	—		$	18.5
Investment in unconsolidated affiliates	$	—	$	1,267.2	$	—		$	—		$	1,267.2
Total assets	$	7,453.6	$	1,266.8	$	189.4		$	(61.3	)	$	8,848.5

Six Months Ended June 30, 2012	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	954.7	$	773.6		$	—		$	(32.6	)	$	1,695.7
Cost of goods sold	400.1		527.9			—			(33.4		)	894.6
Gross margin on revenues	554.6		245.7			—			0.8			801.1
Other operation and maintenance	225.3		85.0			(9.7		)	—			300.6
Depreciation and amortization	122.4		47.7			7.0			—			177.1
Impairment of assets	—		0.3			—			—			0.3
Gain on insurance proceeds	—		(7.5		)	—			—			(7.5		)
Taxes other than income	39.3		13.0			2.7			—			55.0
Operating income (loss)	$	167.6	$	107.2		$	—		$	0.8		$	275.6
Total assets	$	6,833.2	$	2,395.3		$	331.4		$	(208.5	)	$	9,351.4

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Summary of Significant Accounting Policies, Regulated Operations (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013		Dec. 31, 2012
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries	$ 1.7		$ 0
Regulatory Assets, Current	29.8		27.0
Regulatory Assets, Non-Current	501.9		510.6
Fuel clause over recoveries	21.8		109.2
Regulatory Liability, Current	46.3		141.1
Regulatory Liability, Non-Current	244.4		245.1
Smart Grid rider over recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	19.4	[1]	24.1	[1]
Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	5.1	[1]	7.8	[1]
Accrued removal obligations, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Non-Current	219.7		218.2
Pension tracker [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Non-Current	12.6		9.2
Deferred pension credits [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Non-Current	12.1		17.7
Crossroads wind farm rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	11.3	[2]	14.9	[2]
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	8.4	[2]	9.2	[2]
Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	8.4	[2]	2.9	[2]
Regulatory Assets, Non-Current	14.3		12.3
Benefit obligations regulatory asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	357.0		370.6
Income taxes recoverable from customers, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	55.2		54.7
Smart Grid [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	43.4		42.8
Deferred storm expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	17.2		12.7
Unamortized loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	12.4		13.0
Deferred pension expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	$ 2.4		$ 4.5

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

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

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Derivative Instruments and Hedging Activities

6 Months Ended

Jun. 30, 2013

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 risk managed using derivatives instruments is interest rate risk. The Company is also exposed to credit risk in its business operations.

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 (Loss) 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 previously designated as cash flow hedges derivatives for OGE Holdings' 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 operations and natural gas transportation and storage operations (operational gas hedges).  The Company also previously designated as cash flow hedges certain derivatives for certain natural gas storage inventory positions. The Company had no material instruments designated as cash flow hedges at June 30, 2013.

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, 2013 and December 31, 2012, 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 OGE Holdings' asset management activities.  For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

At June 30, 2013 and December 31, 2012, the Company had no material derivative instruments that were not designated as hedging instruments.

Balance Sheet Presentation Related to Derivative Instruments

The Company had no material derivative instruments included in its Condensed Consolidated Balance Sheet at June 30, 2013. The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2012 are as follows:

		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	—	$	0.5
Total		$	—	$	0.5
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.1	$	—
	Other Current Assets	5.0		4.7
Physical Purchases/Sales	Current PRM	0.4		0.3
Total		$	5.5	$	5.0
Total Gross Derivatives (A)		$	5.5	$	5.5

(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, 2012.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for thethreemonths endedJune 30, 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.5	)	$	—		$	—
Interest Rate Swap	—			(0.1		)	—
Total	$	(0.5	)	$	(0.1	)	$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(3.7	)
Natural Gas Financial Futures/Swaps	0.6
Total	$	(3.1	)

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for thesixmonths endedJune 30, 2012.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.2	)	$	5.2		$	—
Interest Rate Swap	—			(0.2		)	—
Total	$	(0.2	)	$	5.0		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(6.1	)
Natural Gas Financial Futures/Swaps	1.0
Total	$	(5.1	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income (Loss) into income (effective portion) and amounts recognized in income (ineffective portion) for the threeandsixmonths endedJune 30, 2012, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the threeandsixmonths endedJune 30, 2012, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

At June 30, 2013 the Company had no derivative instruments that contain credit-risk related contingent features.

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2013

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

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethreeandsixmonths endedJune 30, 2013 and 2012related to the Company's performance units and restricted stock.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Performance units
Total shareholder return	$	1.9	$	2.0	$	3.9	$	3.8
Earnings per share	0.7		0.6		1.3		1.3
Total performance units	2.6		2.6		5.2		5.1
Restricted stock	0.1		0.2		0.2		0.4
Total compensation expense	2.7		2.8		5.4		5.5
Less: Amount paid by unconsolidated affiliates	0.6		—		0.6		—
Net compensation expense	$	2.1	$	2.8	$	4.8	$	5.5
Income tax benefit	$	1.0	$	1.1	$	2.1	$	2.2

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Investment in Unconsolidated Affiliates Related Party Transactions (Details) (Og and E [Member], USD $) In Millions, unless otherwise specified	2 Months Ended	3 Months Ended	6 Months Ended	2 Months Ended
	Jun. 30, 2013	Jun. 30, 2013 Operating Costs Charged [Member]	Jun. 30, 2013 Operating Costs Charged [Member]	Jun. 30, 2013 Natural Gas Transportation [Member]	Jun. 30, 2013 Natural Gas Storage [Member]	Jun. 30, 2013 Natural Gas Purchases [Member]
Related Party Transaction [Line Items]
Operating expenses		$ 7.9	$ 14.6
Related Party Transaction, Due from (to) Related Party						1.2
Revenue from Related Parties	1.3
Related Party Transaction, Purchases from Related Party				$ 5.8	$ 2.3	$ 2.5	[1]

[1] At June 30, 2013, there was $1.2 million of natural gas purchases recorded for these activities.

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Common Equity

6 Months Ended

Jun. 30, 2013

Common Equity [Text Block]

Common Equity

Forward Stock Split

On May 16, 2013, the Company's Board of Directors approved a 2-for-1 forward stock split of the Company's common stock, effective July 1, 2013, which entitled each shareholder of record to receive two shares for every one share of Company stock owned by the shareholder.  In connection with the stock split and as included as Exhibit 3.01 herein, an amendment to the Company's Articles of Incorporation was approved on May 16, 2013 which increased the number of authorized shares of common stock from225 millionto450 million. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 91,588 shares and 198,790 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and sixmonths endedJune 30, 2013 and received proceeds of $3.3 million and $6.4 million, respectively.  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, 2013, there were 4,046,198 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)	2013		2012		2013		2012
Net Income Attributable to OGE Energy	$	91.7	$	93.9	$	114.8	$	131.0
Average Common Shares Outstanding
Basic average common shares outstanding	198.3		197.2		198.0		196.8
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.1		0.6		1.1		0.8
Diluted average common shares outstanding	199.4		197.8		199.1		197.6
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.46	$	0.48	$	0.58	$	0.66
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.46	$	0.47	$	0.58	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Fair Value Measurements

6 Months Ended

Jun. 30, 2013

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 is 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 options 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).

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, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets 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 Company hadnomaterial financial instruments measured at fair value on a recurring basis atJune 30, 2013. The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012 as well as presents the Company's commodity contracts fair value included in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company adopted the Financial Accounting Standards Board accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company posted $0.2 million of collateral at December 31, 2012 which has been included within netting adjustments in the table below. The Company held no collateral at December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company held no Level 3 investments at December 31, 2012.

December 31, 2012
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	5.0		$	5.0		$	—	$	—
Significant other observable inputs (Level 2)	0.5			0.5			3.1		3.8
Total fair value	5.5			5.5			3.1		3.8
Netting adjustments	(5.0		)	(5.2		)	—		—
Total	$	0.5		$	0.3		$	3.1	$	3.8

(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 assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012, 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.

(C) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million at December 31, 2012, 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 fair value and carrying amount of the Company's financial instruments at June 30, 2013 and December 31, 2012.

	June 30, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,154.3	$	2,465.6	$	1,904.2	$	2,401.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.6		10.7		10.7		10.0
OGE Energy Senior Notes	99.9		104.5		99.9		106.3
Enogex LLC Senior Notes	(A)		(A)		448.4		493.4
Enogex LLC Term Loan	(A)		(A)		250.0		250.0

(A) As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company's consolidated financial statements do not include any obligations for the Enogex LLC Senior Notes and Enogex LLC Term Loan as of May 1, 2013.

The Company's long-term debt is valued at the carrying amount.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 and is classified as Level 2 in the fair value hierarchy except for the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 2.6

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Common Equity Forward Stock Split (Details) In Millions, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Common Stock, Shares Authorized	450	225

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Derivative Instruments and Hedging Activities, Quantitative Disclosures Related to Derivative Instruments (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Fair Value Hedging [Member]
Derivative [Line Items]
Fair Value Hedges, Net	$ 0	$ 0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Other Derivatives Not Designated as Hedging Instruments at Fair Value, Net	0	0
Cash Flow Hedging [Member]
Derivative [Line Items]
Cash Flow Hedges Derivative Instruments at Fair Value, Net	$ 0

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Short-Term Debt and Credit Facilities (Tables)

6 Months Ended

Jun. 30, 2013

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 at June 30, 2013.

	Aggregate			Amount		Weighted-Average
Entity	Commitment			Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0		$	478.7	0.31	%	(E)	December 13, 2017	(F)
OG&E (C)	400.0			2.1		0.53	%	(E)	December 13, 2017	(F)
Total	$	1,150.0	(D)	$	480.8	0.31	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2013.

(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, 2013, there was $478.7 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, 2013, there was $2.1 million supporting letters of credit.

(D) Effective May 1, 2013, Enable Midstream Partnersentered into a$1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's$400 millionrevolving credit facility was terminated.

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

(F) In December 2011,the Company andOG&E entered intounsecured five-year revolving credit agreements to total in the aggregate1,150.0 million ($750 millionfor the Company and$400 millionfor OG&E).Each of thecredit facilitiescontainan option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013,the Company andOG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity oftheircredit agreementsto December 13, 2017.

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Commitments and Contingencies (Details) (USD $)			7 Months Ended	10 Months Ended	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Oct. 31, 2013 OG&E minimum fuel purchase commitments [Member]	Oct. 31, 2013 OG&E minimum fuel purchase commitments [Member]	Jun. 30, 2013 OG&E long-term service agreement commitments [Member] McClain Plant [Member]	Jun. 30, 2013 OG&E long-term service agreement commitments [Member] Redbud Plant [Member]	Jun. 30, 2013 Enogex [Member]
Long-term Purchase Commitment [Line Items]
Percentage of OG&E's Projected 2013 Requirements			55.80%	26.10%
Factored-Fired Hours					128,000	24,000
Factored-Fired Starts					3,600
Operating Leases, Future Minimum Payments Due	$ 0
Commitments and Contingencies							0
Estimated Environmental Capital Costs	1,000,000,000
Potential Penalty Under the Federal Clean Air Act	$ 37,500

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Retirement Plans and Postretirement Benefit Plans

6 Months Ended

Jun. 30, 2013

Retirement Plans and Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

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												Restoration of Retirement Income Plan
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)			2013 (B)		2012 (B)		2013 (C)		2012 (C)
Service cost	$	4.5		$	4.5		$	9.5		$	9.0		$	0.3	$	0.2	$	0.6	$	0.5
Interest cost	6.8			7.5			13.4			15.0			0.2		0.2		0.3		0.3
Expected return on plan assets	(11.9		)	(11.5		)	(24.2		)	(23.0		)	—		—		—		—
Amortization of net loss	7.0			6.0			13.2			11.9			0.1		0.1		0.2		0.2
Amortization of unrecognized prior service cost (A)	0.4			0.5			0.9			1.1			—		0.1		0.1		0.3
Total net periodic benefit cost	6.8			7.0			12.8			14.0			0.6		0.6		1.2		1.3
Less: Amount paid by unconsolidated affiliates	1.0			—			1.0			—			—		—		—		—
Net periodic benefit cost (net of unconsolidated affiliates)	$	5.8		$	7.0		$	11.8		$	14.0		$	0.6	$	0.6	$	1.2	$	1.3

(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B) In addition to the$6.4 millionand$7.6 millionof net periodic benefit cost recognizedduring thethreemonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in pension expense during thethreemonths endedJune 30, 2013and2012of$1.2 millionand$2.8 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$13.0 millionand$15.3 millionof net periodic benefit cost recognizedduring thesixmonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in pension expense during thesixmonths endedJune 30, 2013and2012of$3.1 millionand$5.7 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)
Service cost	$	1.0		$	1.1		$	2.2		$	2.1
Interest cost	2.6			3.0			5.2			6.0
Expected return on plan assets	(0.7		)	(0.7		)	(1.3		)	(1.5		)
Amortization of transition obligation	—			0.7			—			1.4
Amortization of net loss	5.4			5.1			10.7			10.2
Amortization of unrecognized prior service cost (A)	(4.2		)	(4.2		)	(8.3		)	(8.3		)
Total net periodic benefit cost	4.1			5.0			8.5			9.9
Less: Amount paid by unconsolidated affiliates	0.4			—			0.4			—
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.7		$	5.0		$	8.1		$	9.9

(A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.

(B) In addition to the$3.7 millionand$5.0 millionof net periodic benefit cost recognizedduring thethreemonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthethreemonths endedJune 30, 2013and2012of$0.2 millionand$0.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$8.1 millionand$9.9 millionof net periodic benefit cost recognizedduring thesixmonths endedJune 30, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthesixmonths endedJune 30, 2013and2012of$0.3 millionand$0.8 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

The capitalized portion of net periodic pension benefit cost was $1.5 million and $2.6 million during the three and sixmonths endedJune 30, 2013 as compared to $1.6 million and $3.1 million during the same period in 2012. The capitalized portion of net periodic postretirement benefit cost was $0.8 million and $1.6 million during the three and sixmonths endedJune 30, 2013 as compared to $1.0 million and $2.0 million during the same period in 2012.

Pension Plan Funding

The Companypreviously reported in its 2012 Form 10-K that it may contribute up to$35 millionto its Pension Plan during 2013. In May 2013,the Companycontributed$35 millionto its Pension Plan. No additional contributions are expected in 2013.

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Income Taxes

6 Months Ended

Jun. 30, 2013

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 to2009or state and local tax examinations by tax authorities for years prior to2005.  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.OG&E 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 production from its wind farmsand earnsOklahoma state tax credits associated withitsinvestments in electric generatingfacilities which further reduce the Company's effective tax rate.

As previously reported in the Company's 2012 Form 10-K, in January 2013, OG&E determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During the first quarter of 2013, OG&E recorded a reserve of$7.8 million ($5.1 millionafter tax) related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized due to management's determination that it is more likely than not that it will be unable to utilize these credits.

As a result of acquiring an equity interest in Enable Midstream Partners, the Company has a lower effective tax rate in conjunction with the formation of Enable Midstream Partners in states with lower state tax rates, which reduced income tax expense for the three months ended June 30, 2013 by $3.9 million. In addition, deferred tax adjustments related to the Company's deconsolidation of Enogex Holdings increased income tax expense for the three months ended June 30, 2013 by $3.9 million.

Acquisition of the equity interest in Enable Midstream Partners on May 1, 2013, is also expected to increase the Company's utilization of net operating loss carryforwards throughout 2013. The Company now projects utilization of approximately $227.0 million ($147.6 million after tax) of Federal net operating loss carryforwards and $42.0 million ($39.6 million after tax) of state net operating loss carryforwards in 2013.

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Rate Matters and Regulation

6 Months Ended

Jun. 30, 2013

Regulated Operations [Abstract]

Rate Matters and Regulation

Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 17 to the Company's Consolidated Financial Statements included in the Company's 2012Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Crossroads Wind Farm

As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 megawatts. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On April 15, 2013, the APSC issued an order authorizing OG&E to recover the Arkansas portion of the cost to construct the Crossroads wind farm, effective retroactively to August 1, 2012. The costs will be recovered through the Energy Cost Recovery Rider.

Market-Based Rate Authority

On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order accepting OG&E's June 2012 triennial market power update.

Fuel Adjustment Clause Review for Calendar Year 2011

On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. On April 9, 2013, the OCC administrative law judge recommended that the OCC find that for the calendar year 2011 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. On June 18, 2013, the OCC issued an order approving the administrative law judge’s recommendation.

Pending Regulatory Matters

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. 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.

Order No. 1000 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, Order No. 1000 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, Order No. 1000 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. Order No. 1000 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. These changes to the "right of first refusal" 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 were filed on November 13, 2012. On May 29, 2013, the Governor signed House Bill 1932 into law which establishes a right of first refusal for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts that interconnect to those incumbent entities' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000.

On July 18, 2013, the FERC issued an order on the SPP's Order No. 1000 compliance filing.  This order accepted in part and rejected in part the SPP's plan for complying with Order No. 1000.  The FERC rejected the SPP's plan to retain the right of first refusal for projects that would operate between 100 kilovolts and 300 kilovolts.  However, the FERC clarified that a right of first refusal was appropriate in certain circumstances.  It is not clear how the FERC's order will relate to the recently enacted Oklahoma law addressing a right of first refusal for lower voltages.  The SPP was ordered to submit another compliance filing by November 15, 2013.

OGE Energy cannot, at this time, determine the precise impactof Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, OGE Energy 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.

Fuel Adjustment Clause Review for Calendar Year 2012

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2013, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs.

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Report of Business Segments

6 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Report of Business Segments

Report of Business Segments

Previously, the Company's business was divided into three segmentsas follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing. On March 14, 2013,OGE Energy entered into a Master Formation Agreement withthe ArcLight groupand CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight groupand CenterPoint Energy, Inc., agreed to form Enable Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPointthat will initially be structured as a private limited partnership. As a result, effective May 1, 2013, OGE Energydeconsolidated its interest in Enogex Holdings LLC andbegan accounting for its interest in Enable Midstream Partners using the equity method of accounting. The Company's business is now divided into two segments for financial reporting purposes as follows: (i) electric utility and (ii) natural gas midstream operations. The formernatural gas transportation and storagesegment andnatural gas gathering and processingsegment have been combined into thenatural gas midstream operationssegment and have been restated for all prior periods presented. Equity in earnings of unconsolidated affiliates in the natural gas midstream operations segment includes OGE Energy's equity interest in Enable Midstream Partners from May 1, 2013 through June 30, 2013. Other than equity in earnings of unconsolidated affiliates, all amounts for the natural gas midstream operations segment are through April 30, 2013. Investment in unconsolidated affiliates in the natural gas midstream operations segment includes OGE Energy's investment in Enable Midstream Partners at June 30, 2013. 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 during the threemonths endedJune 30, 2013 and 2012.

Three Months Ended June 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	574.6	$	166.1	$	—		$	(6.5	)	$	734.2
Cost of goods sold	247.6		129.7		—			(6.7		)	370.6
Gross margin on revenues	327.0		36.4		—			0.2			363.6
Other operation and maintenance	107.0		15.7		(0.7		)	—			122.0
Depreciation and amortization	62.0		9.2		3.2			—			74.4
Taxes other than income	19.9		2.5		0.9			—			23.3
Operating income (loss)	$	138.1	$	9.0	$	(3.4	)	$	0.2		$	143.9
Equity in earnings of unconsolidated affiliates	$	—	$	18.5	$	—		$	—		$	18.5
Investment in unconsolidated affiliates	$	—	$	1,267.2	$	—		$	—		$	1,267.2
Total assets	$	7,453.6	$	1,266.8	$	189.4		$	(61.3	)	$	8,848.5

Three Months Ended June 30, 2012	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	528.0	$	344.0	$	—		$	(17.0	)	$	855.0
Cost of goods sold	204.6		222.6		—			(17.9		)	409.3
Gross margin on revenues	323.4		121.4		—			0.9			445.7
Other operation and maintenance	114.7		42.7		(4.4		)	—			153.0
Depreciation and amortization	62.7		24.3		3.5			—			90.5
Impairment of assets	—		0.1		—			—			0.1
Taxes other than income	18.2		5.7		0.9			—			24.8
Operating income (loss)	$	127.8	$	48.6	$	—		$	0.9		$	177.3
Total assets	$	6,833.2	$	2,395.3	$	331.4		$	(208.5	)	$	9,351.4

Six Months Ended June 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.1	$	630.4	$	—		$	(24.9	)	$	1,635.6
Cost of goods sold	460.6		489.0		—			(26.0		)	923.6
Gross margin on revenues	569.5		141.4		—			1.1			712.0
Other operation and maintenance	212.1		60.9		(3.0		)	—			270.0
Depreciation and amortization	123.3		36.8		6.2			—			166.3
Taxes other than income	43.1		10.5		2.8			—			56.4
Operating income (loss)	$	191.0	$	33.2	$	(6.0	)	$	1.1		$	219.3
Equity in earnings of unconsolidated affiliates	$	—	$	18.5	$	—		$	—		$	18.5
Investment in unconsolidated affiliates	$	—	$	1,267.2	$	—		$	—		$	1,267.2
Total assets	$	7,453.6	$	1,266.8	$	189.4		$	(61.3	)	$	8,848.5

Six Months Ended June 30, 2012	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	954.7	$	773.6		$	—		$	(32.6	)	$	1,695.7
Cost of goods sold	400.1		527.9			—			(33.4		)	894.6
Gross margin on revenues	554.6		245.7			—			0.8			801.1
Other operation and maintenance	225.3		85.0			(9.7		)	—			300.6
Depreciation and amortization	122.4		47.7			7.0			—			177.1
Impairment of assets	—		0.3			—			—			0.3
Gain on insurance proceeds	—		(7.5		)	—			—			(7.5		)
Taxes other than income	39.3		13.0			2.7			—			55.0
Operating income (loss)	$	167.6	$	107.2		$	—		$	0.8		$	275.6
Total assets	$	6,833.2	$	2,395.3		$	331.4		$	(208.5	)	$	9,351.4

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Document and Entity Information Document	6 Months Ended
	Jun. 30, 2013
Document Information [Line Items]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	0001021635
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding	198,353,947

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Commitments and Contingencies Commitments and Contingencies (Notes)

6 Months Ended

Jun. 30, 2013

Long-term Purchase Commitment [Line Items]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

Except as set forth below and in Note 14, the circumstances set forth in Notes 16 and 17 to the Company's Consolidated Financial Statements included in the Company's 2012Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

OG&E Minimum Fuel Purchase Commitments

OG&E has coal contracts for purchases from January 2012 through December 2016. Also, as previously reported, OG&E had entered into multiple month term natural gas contracts for26.1 percentof its 2013 annual forecasted natural gas requirements. In February 2013, through a request for proposal, OG&E entered into various multiple month term natural gas contracts for55.8 percentof its remaining forecasted 2013 natural gas requirements.Additional gas supplies to fulfill OG&E's remaining 2013 natural gas requirements will be acquired through monthly and daily purchases which are expected to be made at market prices.

OG&E Long-Term Service Agreement Commitments

OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant.  The existing contract will expire on January 1, 2015. In May 2013, a new contract was signed that is expected to run for the earlier of128,000factored-fired hours or3,600factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.

OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional24,000factored-fired hours. Based on historical usage and current expectations for future usage, this contract is expected to run until 2027. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

Enable Midstream Partners Transportation Contract

Enable Midstream Partners provides gas transmission delivery services to all of PSO's natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. The PSO contract provides for a monthly demand charge plus variable transportation charges including fuel. The stated term of the PSO contract was set to expire January 1, 2014, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period.  Because neither party provided notice of termination 180 days prior to January 1, 2014, the PSO contract will remain in effect at least through January 1, 2015.

OGE Holdings Noncancellable Operating Leases

As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company has no obligations included in its Consolidated Financial Statements at June 30, 2013 under OGE Holdings' noncancellable lease obligations previously disclosed in the Company's 2012 Form 10-K.

Enogex Energy Resources, Inc. Commitments

As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company has no obligations included in its Consolidated Financial Statements at June 30, 2013, under Enogex Energy Resources, Inc.'s commitments previously disclosed in the Company's 2012 Form 10-K.

Environmental Laws and Regulations

United States v. OG&E (Federal Clean Air Act New Source Review Litigation)

As previously reported, in July 2008, OG&E 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. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects 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.

In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with the EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. OG&E expects to vigorously defend against these claims, but OG&E cannot predict the outcome of such litigation. The Sierra Club, an environmental organization, also has threatened to file a citizen suit under the Federal Clean Air Act alleging similar violations against OG&E, and OG&E expects that the Sierra Club will seek to intervene in the litigation initiated by the EPA. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act.

If OG&E does not prevail and if a new assessment of the projects were to conclude that they caused a significant emissions increase, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including Dry Scrubbers and selective catalytic reduction systems with capital costs in excess of$1.0 billionand pay fines and significant 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$37,500per day for each violation. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs.

Other

In the normal course of business,the Companyis confronted with issues or events that may result in a contingent liability.These generally relate to lawsuits or claims made by third parties, including governmental agencies.When appropriate, management consults with legal counsel and other appropriate experts to assess the claim.If, in management's opinion,the Companyhas 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.At the present time, based on currently available information, except as otherwise stated above, in Note 14 below, under "Environmental Laws and Regulations" in Item 2 of Part 1 and in Item 1 of Part II of this Form 10-Q, in Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I of the Company's 2012Form 10-K, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.