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 endedMarch 31, 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 March 31, 2013, there were 99,116,609 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDEDMARCH 31, 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	27
Item 3. Quantitative and Qualitative Disclosures About Market Risk	43
Item 4. Controls and Procedures	44
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	44
Item 1A. Risk Factors	44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 6. Exhibits	45
Signature	46

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
Atoka	Atoka Midstream LLC joint venture
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
EBITDA	Enogex Holdings earnings before interest, taxes, depreciation and amortization
EER	Enogex Energy Resources LLC, wholly-owned subsidiary of Enogex LLC (prior to June 30, 2012, the legal name was OGE Energy Resources LLC)
Enogex	OGE Holdings, collectively with its subsidiaries
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings
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
Midstream Partnership	Partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
MMBtu	Million British thermal unit
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
Pension Plan	Qualified defined benefit retirement plan
PRM	Price risk management
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, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee;

• 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;

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

• the risk that the Midstream Partnershipmay not be able to successfully integrate the operations of Enogex and CenterPoint; 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
	March 31,
(In millions except per share data)	2013			2012
OPERATING REVENUES
Electric Utility operating revenues	$	455.5		$	426.7
Natural Gas Midstream Operations operating revenues	445.9			414.0
Total operating revenues	901.4			840.7
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	199.4			183.6
Natural Gas Midstream Operations cost of goods sold	353.6			301.7
Total cost of goods sold	553.0			485.3
Gross margin on revenues	348.4			355.4
OPERATING EXPENSES
Other operation and maintenance	148.0			147.6
Depreciation and amortization	91.9			86.6
Impairment of assets	—			0.2
Gain on insurance proceeds	—			(7.5		)
Taxes other than income	33.1			30.2
Total operating expenses	273.0			257.1
OPERATING INCOME	75.4			98.3
OTHER INCOME (EXPENSE)
Interest income	0.1			—
Allowance for equity funds used during construction	1.2			1.9
Other income	14.6			7.7
Other expense	(6.5		)	(1.9		)
Net other income	9.4			7.7
INTEREST EXPENSE
Interest on long-term debt	39.7			39.2
Allowance for borrowed funds used during construction	(0.7		)	(1.1		)
Interest on short-term debt and other interest charges	2.2			2.0
Interest expense	41.2			40.1
INCOME BEFORE TAXES	43.6			65.9
INCOME TAX EXPENSE	15.6			18.4
NET INCOME	28.0			47.5
Less: Net income attributable to noncontrolling interests	4.9			10.4
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	23.1		$	37.1
BASIC AVERAGE COMMON SHARES OUTSTANDING	98.9			98.3
DILUTED AVERAGE COMMON SHARES OUTSTANDING	99.4			98.8
BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.23		$	0.38
DILUTED EARNINGS PER AVERAGE COMMON SHARES ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.23		$	0.38
DIVIDENDS DECLARED PER COMMON SHARE	$	0.4175		$	0.3925

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
	March 31,
(In millions)	2013			2012
Net income	$	28.0		$	47.5
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4 and $0.4, respectively	0.9			0.8
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.3 and $0.3, respectively	0.5			0.5
Amortization of prior service cost, net of tax of ($0.3) and ($0.3), respectively	(0.5		)	(0.5		)
Deferred commodity contracts hedging gains reclassified in net income, net of tax of ($0.1) and ($1.7), respectively	(0.1		)	(3.3		)
Amortization of deferred interest rate swap hedging losses, net of tax of $0.1 and $0.1, respectively	0.1			0.1
Other comprehensive income (loss), net of tax	0.9			(2.4		)
Comprehensive income (loss)	28.9			45.1
Less:  Comprehensive income attributable to noncontrolling interests	5.0			9.5
Total comprehensive income attributable to OGE Energy	$	23.9		$	35.6

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

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
(In millions)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	28.0		$	47.5
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	92.9			87.6
Impairment of assets	—			0.2
Deferred income taxes and investment tax credits, net	15.4			18.4
Allowance for equity funds used during construction	(1.2		)	(1.9		)
(Gain) loss on disposition and abandonment of assets	(8.7		)	0.5
Gain on insurance proceeds	—			(7.5		)
Stock-based compensation	(8.3		)	(11.8		)
Price risk management assets	0.1			(0.5		)
Price risk management liabilities	0.1			(4.9		)
Regulatory assets	5.5			5.6
Regulatory liabilities	(4.1		)	(3.4		)
Other assets	(0.1		)	1.4
Other liabilities	6.3			5.2
Change in certain current assets and liabilities
Accounts receivable, net	8.4			54.8
Accrued unbilled revenues	7.8			6.0
Fuel, materials and supplies inventories	(7.7		)	3.3
Gas imbalance assets	(3.7		)	(4.0		)
Fuel clause under recoveries	(0.4		)	1.8
Other current assets	(4.1		)	(6.3		)
Accounts payable	16.5			(59.2		)
Gas imbalance liabilities	0.7			(1.5		)
Fuel clause over recoveries	(27.6		)	31.5
Other current liabilities	(56.6		)	(42.5		)
Net Cash Provided from Operating Activities	59.2			120.3
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(325.1		)	(311.1		)
Proceeds from insurance	—			6.1
Reimbursement of capital expenditures	—			9.7
Proceeds from sale of assets	35.6			0.2
Net Cash Used in Investing Activities	(289.5		)	(295.1		)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term debt	276.1			212.2
Issuance of common stock	3.2			3.7
Distributions to noncontrolling interest partners	(2.5		)	(5.6		)
Dividends paid on common stock	(41.2		)	(38.5		)
Net Cash Provided from Financing Activities	235.6			171.8
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5.3			(3.0		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1.8			4.6
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	7.1		$	1.6

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

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)	March 31, 2013 (Unaudited)		December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7.1	$	1.8
Accounts receivable, less reserve of $1.7 and $2.6, respectively	286.9		295.3
Accrued unbilled revenues	49.6		57.4
Income taxes receivable	7.2		7.2
Fuel inventories	99.7		93.3
Materials and supplies, at average cost	82.2		80.9
Price risk management	0.4		0.5
Gas imbalances	12.7		9.0
Deferred income taxes	40.6		187.7
Fuel clause under recoveries	0.4		—
Assets held for sale	—		25.5
Other	39.7		35.6
Total current assets	626.5		794.2
OTHER PROPERTY AND INVESTMENTS, at cost	55.9		52.2
PROPERTY, PLANT AND EQUIPMENT
In service	11,656.8		11,504.4
Construction work in progress	543.6		387.5
Total property, plant and equipment	12,200.4		11,891.9
Less accumulated depreciation	3,620.0		3,547.1
Net property, plant and equipment	8,580.4		8,344.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	502.6		510.6
Intangible assets, net	126.0		127.4
Goodwill	39.4		39.4
Other	51.0		53.6
Total deferred charges and other assets	719.0		731.0
TOTAL ASSETS	$	9,981.8	$	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)	March 31, 2013 (Unaudited)			December 31, 2012
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	707.0		$	430.9
Accounts payable	409.5			396.7
Dividends payable	41.4			41.2
Customer deposits	71.3			70.3
Accrued taxes	28.8			48.1
Accrued interest	35.7			55.0
Accrued compensation	37.1			55.2
Price risk management	0.4			0.3
Gas imbalances	5.7			5.0
Fuel clause over recoveries	81.6			109.2
Other	63.7			64.5
Total current liabilities	1,482.2			1,276.4
LONG-TERM DEBT	2,848.7			2,848.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	399.9			399.8
Deferred income taxes	1,817.7			1,948.8
Deferred investment tax credits	3.4			3.9
Regulatory liabilities	245.5			245.1
Deferred revenues	38.5			37.7
Other	93.6			89.5
Total deferred credits and other liabilities	2,598.6			2,724.8
Total liabilities	6,929.5			6,849.8
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,039.7			1,047.4
Retained earnings	1,754.1			1,772.4
Accumulated other comprehensive loss, net of tax	(48.3		)	(49.1		)
Treasury stock, at cost	—			(3.5		)
Total OGE Energy stockholders' equity	2,745.5			2,767.2
Noncontrolling interests	306.8			305.2
Total stockholders' equity	3,052.3			3,072.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,981.8		$	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	—		—			23.1			—			4.9			—			28.0
Other comprehensive income (loss), net of tax	—		—			—			0.8			0.1			—			0.9
Dividends declared on common stock	—		—			(41.4		)	—			—			—			(41.4		)
Issuance of common stock	—		3.2			—			—			—			—			3.2
Stock-based compensation and other	—		(10.9		)	—			—			(0.9		)	3.5			(8.3		)
Distributions to noncontrolling interest partners	—		—			—			—			(2.5		)	—			(2.5		)
Balance at March 31, 2013	$	1.0	$	1,038.7		$	1,754.1		$	(48.3	)	$	306.8		$	—		$	3,052.3
Balance at December 31, 2011	$	1.0	$	1,034.3		$	1,574.8		$	(40.6	)	$	256.0		$	(6.2	)	$	2,819.3
Net income	—		—			37.1			—			10.4			—			47.5
Other comprehensive income (loss), net of tax	—		—			—			(1.5		)	(0.9		)	—			(2.4		)
Dividends declared on common stock	—		—			(38.7		)	—			—			—			(38.7		)
Issuance of common stock	—		3.7			—			—			—			—			3.7
Stock-based compensation and other	—		(16.7		)	—			—			(2.6		)	5.9			(13.4		)
Distributions to noncontrolling interest partners	—		—			—			—			(5.6		)	—			(5.6		)
Balance at March 31, 2012	$	1.0	$	1,021.3		$	1,573.2		$	(42.1	)	$	257.3		$	(0.3	)	$	2,810.4

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 three business segments:  (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing.  All significant intercompany transactions have been eliminated in consolidation.

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.

Enogex is a provider of integrated natural gas midstream services.Enogex is engaged in the business of gathering, processing, transporting and storing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.Enogex's operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.AtMarch 31, 2013, OGE Energy indirectly owns a79.9 percentmembership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company.  At March 31, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements as OGE Energy had a controlling financial interest over the operations of Enogex Holdings.  Also, at March 31, 2013, Enogex LLC held a 50 percent ownership interest in Atoka.  At March 31, 2013, the Company consolidated Atoka in its Condensed Consolidated Financial Statements as Enogex acted as the managing member of Atoka and had control over the operations of Atoka.

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 the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint. This transaction closed on May 1, 2013.Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributedEnogex LLCto the Midstream Partnershipand CenterPoint Energy, Inc. contributed its midstream natural gas business to the Midstream Partnership.At May 1, 2013, OGE Energy holds28.5 percentof the limited partners interests, CenterPoint holds58.3 percentof the limited partner interests and the ArcLight group holds13.2 percentof the limited partner interests in the Midstream Partnership. The general partner of the Midstream Partnership 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 Energy deconsolidated its interest in Enogex LLC and will account for its interest in the Midstream Partnership under the equity method of accounting.For additional information regarding the Midstream Partnership, see Note 3.

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 atMarch 31, 2013andDecember 31, 2012and the results of its operations and cash flows for the threemonths endedMarch 31, 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 threemonths endedMarch 31, 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.

8

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)	March 31, 2013		December 31, 2012
Regulatory Assets
Current
Crossroads wind farm rider under recovery (A)	$	13.4	$	14.9
Oklahoma demand program rider under recovery (A)	9.4		9.2
Fuel clause under recoveries	0.4		—
Other (A)	7.6		2.9
Total Current Regulatory Assets	$	30.8	$	27.0
Non-Current
Benefit obligations regulatory asset	$	364.1	$	370.6
Income taxes recoverable from customers, net	54.9		54.7
Smart Grid	42.9		42.8
Unamortized loss on reacquired debt	12.7		13.0
Deferred storm expenses	12.3		12.7
Deferred pension expenses	3.4		4.5
Other	12.3		12.3
Total Non-Current Regulatory Assets	$	502.6	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	81.6	$	109.2
Smart Grid rider over recovery (B)	21.6		24.1
Other (B)	6.5		7.8
Total Current Regulatory Liabilities	$	109.7	$	141.1
Non-Current
Accrued removal obligations, net	$	219.4	$	218.2
Deferred pension credits	14.9		17.7
Pension tracker	11.2		9.2
Total Non-Current Regulatory Liabilities	$	245.5	$	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.

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Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during thethreemonths endedMarch 31, 2013and2012.

	Three Months Ended
	March 31,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled	(0.1		)	—
Accretion expense	0.6			0.4
Revisions in estimated cash flows (A)	—			26.7
Balance at March 31	$	54.5		$	51.9

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

Accumulated Other Comprehensive Income (Loss)

In February 2013, the Financial Accounting Standards Board issued "Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." The new standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, the new standard requires an entity to present significant amounts reclassified out of accumulated other comprehensive income by the respective line items in net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The Company adopted the new standard effective January 1, 2013 and these disclosures have been included below.

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to OGE Energy during thethreemonths endedMarch 31, 2013. At both March 31, 2013 and December 31, 2012, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka. 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)	0.9			—		0.5			(0.5		)	(0.1		)	0.1			0.1			0.8
Balance at March 31, 2013	$	(48.4	)	$	0.1	$	(15.2	)	$	6.7		$	—		$	(0.4	)	$	(8.9	)	$	(48.3	)

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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 thethreemonths endedMarch 31, 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
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)	$	(1.3	)	(A)
	(1.3		)	Total before tax
	(0.4		)	Tax benefit
	(0.9		)	Net of tax
	(0.1		)	Noncontrolling interest
	$	(0.8	)	Net of tax and noncontrolling interest
Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.8	)	(A)
Prior service cost	0.8			(A)
	—			Total before tax
Total reclassifications for the period	$	(0.8	)	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 12 for additional information).

Reclassifications

As discussed in Note 13, during the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization.The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented to conform to the 2013 presentation.

2. Gas Gathering Divestiture

Texas Panhandle Gathering Divestiture

As previously reported in the Company's 2012 Form 10-K, on January 2, 2013, Enogex and one of its five largest customers entered into new agreements, effective January 1, 2013, relating to the customer's gathering and processing volumes on the Texas portion of Enogex's system. The effects of this new arrangement are (i) a fixed-fee processing agreement replaced the previous keep-whole agreement, (ii) the acreage dedicated by the customer to Enogex for gathering and processing in Texas was increased for an extended term and (iii) the sale by Enogex of certain gas gathering assets in the Texas Panhandle portion of Enogex's system to this customer for cash proceeds of approximately$35 million. Enogex recognized a pre-tax gain of$9.9 millionin the first quarter of 2013 in its natural gas gathering and processing segment from the sale of these assets which is included in Other Income in the Condensed Consolidated Statements of Income.

3. OGE Energy Midstream Partnership with CenterPoint Energy, Inc.

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 the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint that will initially be structured as a private limited partnership. This transaction closed on May 1, 2013.

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Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributed100 percentof the equity interests inEnogex LLCto the Midstream Partnership. CenterPoint Energy Field Services, LLC, a Delaware limited liability company and wholly owned subsidiary of CenterPoint, was converted into a Delaware limited partnership that became the Midstream Partnership. CenterPoint contributed to the Midstream Partnership its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC, a Delaware limited liability company, CenterPoint Energy - Mississippi River Transmission, LLC, a Delaware limited liability company, and certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute49 percentof its interest in Southeast Supply Header, LLC, a Delaware limited liability company. CenterPoint Energy Field Services, LLC provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States that interconnect with CenterPoint Energy Gas Transmission Company, LLC and CenterPoint Energy - Mississippi River Transmission, LLC pipelines, as well as other interstate and intrastate pipelines. As of December 31, 2012, CenterPoint Energy Field Services, LLC gathered an average of approximately 2.5 billion cubic feet per day of natural gas. In addition, CenterPoint Energy Field Services, LLC has the capacity available to treat up to 2.5 billion cubic feet per day and process nearly 625 million cubic feet per day of natural gas. CenterPoint Energy Gas Transmission Company, LLC is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas and includes the 1.9 billion cubic feet per day pipeline from Carthage, Texas to Perryville, Louisiana, which CenterPoint Energy Gas Transmission Company, LLC operates as a separate line with a fixed fuel rate. CenterPoint Energy - Mississippi River Transmission, LLC is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Illinois and Missouri. CenterPoint indirectly owns 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. A wholly owned indirect subsidiary of Spectra Energy Corp. owns the remaining 50 percent interest in Southeast Supply Header, LLC. Upon closing, CenterPoint indirectly contributed 49 percent of its interest in the Southeast Supply Header, LLC to the Midstream Partnership. Upon receipt of certain consents, CenterPoint will contribute the remainder of its interest to the Midstream Partnership.

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 May 1, 2013, OGE Energy holds28.5 percentof the limited partners interests, CenterPoint holds58.3 percentof the limited partner interests and the ArcLight group holds13.2 percentof the limited partner interests in the Midstream Partnership, provided, however, if CenterPoint obtains the approvals required to contribute its remaining indirect interest in Southeast Supply Header, LLC within 90 days after closing, CenterPoint will instead hold 59 percent of the limited partner interests, OGE would hold 28 percent of the limited partners interest and the ArcLight group would hold 13 percent of the limited partners interest.

After the expiration of the 90-day period after closing, CenterPoint has certain put rights, and the Midstream Partnership has certain call rights, exercisable with respect to any interest in Southeast Supply Header, LLC retained by CenterPoint following the formation of the Midstream Partnership, under which CenterPoint would contribute to the Midstream Partnership 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 the Midstream Partnership were to exercise such call right, CenterPoint's retained interest in Southeast Supply Header, LLC would be contributed to the Midstream Partnership 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 the Midstream Partnership or from the Midstream Partnership 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 the Midstream Partnership 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 the Midstream Partnership following an initial public offering of the Midstream Partnership. In addition, for a period of time, the ArcLight group will have board observation rights and approval rights over certain material activities of the Midstream Partnership, 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 the Midstream Partnership 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 Energy deconsolidated its interest in Enogex LLC and will account for its interest in the Midstream Partnership under 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 the Midstream Partnership in an initial public offering. OGE Energy can give no assurances that the initial public offering will be consummated. Prior to consummating the initial public offering, OGE Energy, CenterPoint Energy, Inc. and the Midstream Partnership will need to complete the negotiation of the financial and other terms, including the initial public offering price. In addition, consummation of the initial public offering is subject to market

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conditions. For so long as the ArcLight group maintains a minimum ownership percentage, the ArcLight group is entitled to consult with the Midstream Partnership in connection with the initial public offering. The Midstream Partnership 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.

In connection with the formation of the Midstream Partnership, on May 1, 2013, the Midstream Partnership entered into a $1.05 billion three-year senior unsecured term loan facility, the proceeds of which were used to repay $1.05 billion of intercompany indebtedness owed to CenterPoint. CenterPoint has guaranteed collection of the Midstream Partnership's obligations under the term loan, which guarantee is subordinated to all senior debt of CenterPoint. Effective May 1, 2013, the Midstream Partnership also 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.

At March 31, 2013, Enogex LLC was obligated on approximately $700 million, in the aggregate, in indebtedness under its term loan, its revolving credit agreement and two series of its senior notes maturing in years 2014 and 2020. Certain of the entities contributed to the Midstream Partnership by CenterPoint are obligated on approximately $363 million of indebtedness owed to a wholly owned subsidiary of CenterPoint that is scheduled to mature in 2017.

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 the Midstream Partnership. 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 the Midstream Partnership or (ii) at least 20 percent of the limited partner interests of the Midstream Partnership. "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 the Midstream Partnership), the acquiring party will be required to offer the Midstream Partnership 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 the Midstream Partnership if the acquiring party intends to cease using them in Midstream Operations within 12 months. If the Midstream Partnership 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 board observation rights, the ArcLight group will be prohibited from pursuing any transaction independently from the Midstream Partnership (i) if the ArcLight group's consent is required for the Midstream Partnership to pursue such transaction and (ii) the ArcLight group affirmatively votes not to consent to such transaction.

4. Noncontrolling Interests

There were no contributions by OGE Holdings or the ArcLight group to Enogex Holdings during the threemonths endedMarch 31, 2013.

Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings makes quarterly distributions to its partners. The following table summarizes the quarterly distributions during the threemonths endedMarch 31, 2013.

(In millions)	OGE Holdings' Portion		ArcLight group's Portion		Total Distribution
First quarter 2013	$	10.0	$	2.5	$	12.5

During the threemonths endedMarch 31, 2013, Atoka's noncontrolling interest partner made no contributions to Atoka. Enogex LLC made no distributions during the threemonths endedMarch 31, 2013 to its Atoka partner, as there is no minimum distribution requirement related to Atoka.

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5. 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 accessibleat 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 thereporting entity'sown 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 following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at March 31, 2013 and December 31, 2012 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at March 31, 2013 and 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 $0.1 million and $0.2 million of collateral at March 31, 2013 and December 31, 2012, respectively, which has been included within netting adjustments in the table below. The Company held no collateral at March 31, 2013 or December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012. The Company held no Level 1 investments at March 31, 2013 and no Level 3 investments at March 31, 2013 or December 31, 2012.

March 31, 2013
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Significant other observable inputs (Level 2)	$	0.5		$	0.6		$	4.2	$	4.8
Total fair value	0.5			0.6			4.2		4.8
Netting adjustments	(0.1		)	(0.2		)	—		—
Total	$	0.4		$	0.4		$	4.2	$	4.8
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 $8.5 million and $5.9 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(C) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.1 million and $1.2 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the fair value and carrying amount of the Company's financial instruments, including derivative contracts related to the Company's PRM activities, atMarch 31, 2013 and December 31, 2012.

	March 31, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
PRM Assets
Energy Derivative Contracts	$	0.4	$	0.4	$	0.5	$	0.5
PRM Liabilities
Energy Derivative Contracts	$	0.4	$	0.4	$	0.3	$	0.3
Long-Term Debt
OG&E Senior Notes	$	1,904.3	$	2,368.3	$	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		10.3		10.7		10.0
OGE Energy Senior Notes	99.9		105.6		99.9		106.3
Enogex LLC Senior Notes	448.5		492.1		448.4		493.4
Enogex LLC Term Loan	250.0		250.0		250.0		250.0

The carrying value of the financial instruments included in the Condensed Consolidated Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount.The valuation of the Company's energy derivative contracts was determined generally based on quoted market prices.  However, in certain instances where market quotes are not

15

available, other valuation techniques or models are used to estimate market values.  The valuation of instruments also considers the credit risk of the counterparties.The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

6. Derivative Instruments and Hedging Activities

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

Commodity Price Risk

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

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

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

• natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage Enogex's natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the CondensedConsolidatedBalance Sheets and earnings are recognized in the period in which physical delivery of the commodity occurs.Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by Enogex's operations, (ii) commodity contracts for the purchase and sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

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

Interest Rate Risk

The Company's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper.  The Company manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates.  The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes.  Interest rate derivatives are used solelyto 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

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instrument.Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring.If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing operations and natural gas transportation and storage operations (operational gas hedges).  The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex had no instruments designated as cash flow hedges at March 31, 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.

AtMarch 31, 2013andDecember 31, 2012, the Company hadnoderivative instruments that were designated as fair value hedges.

Derivatives Not Designated as Hedging Instruments

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

Quantitative Disclosures Related to Derivative Instruments

At March 31, 2013, the Company had the following derivative instruments that were not designated as hedging instruments.

(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	7.0	71.3
Fixed Swaps/Futures	0.1	0.1
Basis Swaps	5.2	11.6

(A) Natural gas in MMBtu's.  

(B) 94.2 percent of the natural gas contracts have durations of one year or less, 4.2 percenthave durations of more than one year and less than two years and 1.6 percenthave durations of more than two years.

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

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

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Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet atMarch 31, 2013are as follows:

		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	0.1	$	0.2
Physical Purchases/Sales	Current PRM	0.4		0.4
Total		$	0.5	$	0.6
Total Gross Derivatives (A)		$	0.5	$	0.6

(A) See Note 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet atMarch 31, 2013.

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet atDecember 31, 2012are 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 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet atDecember 31, 2012.

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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 the three months endedMarch 31, 2013.

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		$	—
Interest Rate Swap	—		(0.2		)	—
Total	$	—	$	—		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.3	)
Total	$	(0.3	)

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months endedMarch 31, 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	$	0.3	$	5.2		$	—
Interest Rate Swap	—		(0.2		)	—
Total	$	0.3	$	5.0		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(2.4	)
Natural Gas Financial Futures/Swaps	0.4
Total	$	(2.0	)

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 threemonths endedMarch 31, 2013 and 2012, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the threemonths endedMarch 31, 2013 and 2012, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, the Company would have been required to postnocash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position atMarch 31, 2013.  The Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

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7. Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethreemonths endedMarch 31, 2013 and 2012related to the Company's performance units and restricted stock.

	Three Months Ended
	March 31,
(In millions)	2013		2012
Performance units
Total shareholder return	$	2.0	$	1.8
Earnings per share	0.6		0.7
Total performance units	2.6		2.5
Restricted stock	0.1		0.2
Total compensation expense	$	2.7	$	2.7
Income tax benefit	$	1.0	$	1.1

The Company has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During thethreemonths endedMarch 31, 2013, there were62,632 of treasury stock shares and 258,260shares 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 thethreemonths endedMarch 31, 2013, there were332sharesof restricted stock returned to the Company to satisfy tax liabilities. The Company received $0.2 million during the threemonths endedMarch 31, 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 threemonths endedMarch 31, 2013 due to the Company being in a tax net operating loss position in 2013.

The following table summarizes the activity of the Company's stock-based compensation during thethreemonths endedMarch 31, 2013.

	Units/Shares	Fair Value
Grants
Performance units (Total shareholder return)	156,974	$	58.61
Performance units (Earnings per share)	37,094	$	53.45
Restricted stock	2,970	$	59.41
Conversions
Performance units (Total shareholder return) (A)	188,631	N/A
Performance units (Earnings per share) (A)	62,880	N/A

(A) Performance units were converted based on a payout ratio of200 percentof the target number of performance units granted in February2010and are included in the258,260 and 62,632shares of common stock issued during thethreemonths endedMarch 31, 2013as discussed above.

8. Income Taxes

The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions.With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior 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 farms.  In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

On January 2, 2013, the American Taxpayer Relief Act of 2012 was signed into law. Among other things, the law included an extension of bonus depreciation for one year for property generally placed in service before January 1, 2014. Because this new law was enacted in 2013, GAAP requires the law to be considered retroactive legislation, the impact of which must be recorded in the period enacted. The impact of the new law was recorded during the first quarter of 2013 in the Condensed Consolidated

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Financial Statements as an increase in Deferred Tax Liabilities with a corresponding increase in Deferred Tax Assets related to the net operating loss. With additional bonus depreciation in 2013, the amount of net operating loss classified as a Current Deferred Tax Asset is decreased. Accordingly, a portion of the Current Deferred Tax Asset was reclassified to non-current.

As previously reported in the Company's 2012 Form 10-K, in January 2013, OG&E learned 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.

9. Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 53,601 shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the threemonths endedMarch 31, 2013 and received proceeds of $3.2 million.  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 March 31, 2013, there were 2,068,893 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
	March 31,
(In millions)	2013		2012
Net Income Attributable to OGE Energy	$	23.1	$	37.1
Average Common Shares Outstanding
Basic average common shares outstanding	98.9		98.3
Effect of dilutive securities:
Contingently issuable shares (performance units)	0.5		0.5
Diluted average common shares outstanding	99.4		98.8
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.23	$	0.38
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.23	$	0.38
Anti-dilutive shares excluded from earnings per share calculation	—		—

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10. Long-Term Debt

AtMarch 31, 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)
0.23% - 0.28%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.22% - 0.29%	Muskogee Industrial Authority, January 1, 2025	32.4
0.18% - 0.20%	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.

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11. 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$707.0 millionand$430.9 millionatMarch 31, 2013andDecember 31, 2012, respectively. The following table provides information regarding the Company's revolving credit agreements and available cash at March 31, 2013.

Revolving Credit Agreements and Available Cash
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	663.9	0.38	%	(E)	December 13, 2016
OG&E (C)	400.0		45.2		0.33	%	(E)	December 13, 2016
Enogex LLC (D)	400.0		—		—	%	(E)	See (D) below
	1,550.0		709.1		0.38	%
Cash	7.1		N/A		N/A			N/A
Total	$	1,557.1	$	709.1	0.38	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 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 March 31, 2013, there was $663.9 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 March 31, 2013, there was $43.1 million in outstanding commercial paper borrowings and $2.1 million in letters of credit.

(D) This bank facility was available to provide revolving credit borrowings for Enogex LLC. Effective May 1, 2013, the Midstream Partnershipentered 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.

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

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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12. Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows:

Net Periodic Benefit Cost

	Pension Plan						Restoration of Retirement Income Plan
	Three Months Ended						Three Months Ended
	March 31,						March 31,
(In millions)	2013 (B)			2012 (B)			2013 (B)		2012 (B)
Service cost	$	5.0		$	4.5		$	0.3	$	0.3
Interest cost	6.6			7.5			0.1		0.1
Expected return on plan assets	(12.3		)	(11.5		)	—		—
Amortization of net loss	6.2			5.9			0.1		0.1
Amortization of unrecognized prior service cost (A)	0.5			0.6			0.1		0.2
Net periodic benefit cost	$	6.0		$	7.0		$	0.6	$	0.7

(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$6.6 millionand$7.7 millionof net periodic benefit cost recognizedduring thethreemonths endedMarch 31, 2013and2012, respectively, OG&E recognized an increase in pension expense during thethreemonths endedMarch 31, 2013and2012of$1.9 millionand$2.9 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
	March 31,
(In millions)	2013 (B)			2012 (B)
Service cost	$	1.2		$	1.0
Interest cost	2.6			3.0
Expected return on plan assets	(0.6		)	(0.8		)
Amortization of transition obligation	—			0.7
Amortization of net loss	5.3			5.1
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)
Net periodic benefit cost	$	4.4		$	4.9

(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$4.4 millionand$4.9 millionof net periodic benefit cost recognizedduring thethreemonths endedMarch 31, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthethreemonths endedMarch 31, 2013and2012of$0.1 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).

The capitalized portion of net periodic pension benefit cost was $1.1 million during the threemonths endedMarch 31, 2013 as compared to $1.5 million during the same period in 2012. The capitalized portion of net periodic postretirement benefit cost was $0.8 million during the threemonths endedMarch 31, 2013 as compared to $1.0 million during the same period in 2012.

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13. Report of Business Segments

Previously, the Company's business was divided into four segmentsas follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. During the third quarter of 2012,the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization.The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented. As a result of this change, the Company's business is now divided into three segments for financial reporting purposes as follows: (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing. 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 endedMarch 31, 2013 and 2012.

Three Months Ended March 31, 2013	Electric Utility		Natural Gas Transportation and Storage		Natural Gas Gathering and Processing		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	455.5	$	216.4	$	317.9	$	—		$	(88.4	)	$	901.4
Cost of goods sold	213.0		182.7		246.4		—			(89.1		)	553.0
Gross margin on revenues	242.5		33.7		71.5		—			0.7			348.4
Other operation and maintenance	105.1		10.9		34.3		(2.3		)	—			148.0
Depreciation and amortization	61.3		5.8		21.8		3.0			—			91.9
Taxes other than income	23.2		4.8		3.2		1.9			—			33.1
Operating income (loss)	$	52.9	$	12.2	$	12.2	$	(2.6	)	$	0.7		$	75.4
Total assets	$	7,138.4	$	2,453.0	$	1,948.9	$	387.2		$	(1,945.7	)	$	9,981.8

Three Months Ended March 31, 2012	Electric Utility		Natural Gas Transportation and Storage		Natural Gas Gathering and Processing			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	426.7	$	169.5	$	304.5		$	—		$	(60.0	)	$	840.7
Cost of goods sold	195.5		131.8		217.9			—			(59.9		)	485.3
Gross margin on revenues	231.2		37.7		86.6			—			(0.1		)	355.4
Other operation and maintenance	110.6		12.1		30.1			(5.3		)	0.1			147.6
Depreciation and amortization	59.7		5.6		17.8			3.5			—			86.6
Impairment of assets	—		—		0.2			—			—			0.2
Gain on insurance proceeds	—		—		(7.5		)	—			—			(7.5		)
Taxes other than income	21.1		4.8		2.5			1.8			—			30.2
Operating income (loss)	$	39.8	$	15.2	$	43.5		$	—		$	(0.2	)	$	98.3
Total assets	$	6,632.8	$	1,950.3	$	1,574.1		$	257.7		$	(1,340.4	)	$	9,074.5

14. Commitments and Contingencies

Except as set forth below and in Note 15, 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

25

natural gas requirements will be acquired through additional requests for proposal in mid-2013, along with monthly and daily purchases, all of which are expected to be made at market prices.

Environmental Laws and Regulations

OG&E Notice of Violation

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. OG&E cannot predict at this time when or if litigation will be filed against it as a result of the notice of violation and, if litigation is filed, OG&E cannot predict the outcome of such litigation, but at this time has no reason to believe that it has not acted in compliance with the Federal Clean Air Act. 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 entered an agreement with the Sierra Club to toll the statute of limitations with respect to claims the Sierra Club may assert. The EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment and 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.

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 15 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.

15. 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 Matter

OG&E 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

26

Crossroads wind farm, effective retroactively to August 1, 2012. The costs will be recovered through the Energy Cost Recovery Rider.

Pending Regulatory Matters

OG&E 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 December 19, 2012, witnesses for the OCC Staff filed responsive testimony recommending that the OCC approve OG&E's fuel adjustment clause costs and recoveries for the calendar year 2011 and recommending that the OCC find that OG&E's electric generation, purchased power, fuel procurement and other fuel related practices, policies and decisions during calendar year 2011 were fair, just and reasonable and prudent.  The Oklahoma Industrial Energy Consumers filed a statement of position on December 19, 2012 and did not challenge OG&E's application of its fuel adjustment clause or prudency.  The Oklahoma Industrial Energy Consumers reserved its right to file rebuttal testimony, cross examine witnesses and amend its statement of position should circumstances change or additional information becomes available in the course of this proceeding. On January 7, 2013, the Oklahoma Attorney General filed a statement of position stating that after reviewing the case information the Attorney General has no reason at this time to dispute the findings of the OCC Staff.  On April 9, 2013, a hearing was held in this matter, at which time 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. OG&E expects to receive an order from the OCC by the end of the second quarter of 2013.

Enogex 2013 Fuel Filing

On March 1, 2013, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2013 through March 31, 2014). The deadline for interventions and protests on the filing was March 18, 2013 and no protests were filed. A FERC order is pending.

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

Introduction

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through three business segments:  (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing.

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.

Enogex is a provider of integrated natural gas midstream services.Enogex is engaged in the business of gathering, processing, transporting and storing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.Enogex's operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.AtMarch 31, 2013, OGE Energy indirectly owns a79.9 percentmembership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC.

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 the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint. This transaction closed on May 1, 2013.Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributedEnogex LLCto the Midstream Partnershipand CenterPoint Energy, Inc. contributed its midstream natural gas business to the Midstream Partnership.At May 1, 2013, OGE Energy holds28.5 percentof the limited partners interests, CenterPoint holds58.3 percentof the limited partner interests and the ArcLight group holds13.2 percentof the limited partner interests in the Midstream Partnership. The general partner of the Midstream Partnership 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 Energy deconsolidated its interest in Enogex LLC and will account for its interest in the Midstream

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Partnership under the equity method of accounting.The Company believes that this transaction forming the Midstream Partnership is consistent with the Company's strategy as the stronger financial and operational capabilities of the new Midstream Partnership should allow the Company to realize the full potential of its natural gas midstream assets. For additional information regarding the Midstream Partnership, see Note 3 of Notes to Condensed Consolidated Financial Statements.

Overview

Company Strategy

The Company'smission is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure and meet individual customers' needs for energy and related services 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 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 EndedMarch 31, 2013as Compared toThreeMonths EndedMarch 31, 2012

Net income attributable to OGE Energy was$23.1 million, or$0.23 per diluted share, during thethreemonths endedMarch 31, 2013as compared to$37.1 million, or$0.38per diluted share,during the same period in2012. Thedecreasein net income attributable to OGE Energy of$14.0 million, or37.7 percent, during thethreemonths endedMarch 31, 2013as compared to the same period in2012was primarily due to:

• an increasein net income at OG&E of$0.9 million, or7.4 percent, primarily due to (i) a higher gross margin mainly attributable to increased transmission revenue and higher usage partially offset by lower recovery of investments and (ii) lower other operation and maintenance expense. These increases in net income were partially offset by higher income tax expense;

• a decrease in net income attributable to Enogex of $12.7 million, or 50.8 percent, or $0.13 per diluted share of the Company's common stock, primarily due to (i) a lower gross margin reflecting lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex’s five largest customers from keep-whole to fixed-feepartially offset byincreased gathering rates and volumes and inlet processing volumes associated with ongoing expansion projectsand the gas gathering assets acquired in August 2012, (ii) higher other operation and maintenance expense, (iii) higher depreciation and amortization expense and (iv) a gain on insurance proceeds during the threemonths endedMarch 31, 2012. These decreases in net income were partially offset by higher other income, primarily due to a pre-tax gain of$9.9 millionrelated to the sale of certain gas gathering assets in the Texas Panhandle in January 2013, and lower income tax expense; and

• a decrease in net income attributable to OGE Energy of $2.2 million, or $0.02 per diluted share of 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 expenses related to the Midstream Partnership as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.

Non-Recurring Items.During thethreemonths endedMarch 31, 2013, Enogex had an increase in net income of$6.1 millionrelated to a gain on the sale of certain gas gathering assets in the Texas Panhandle, as discussed below, which Enogex does not consider to be reflective of its ongoing performance.

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During thethreemonths endedMarch 31, 2012, Enogex had an increase in net income of$4.6 milliondue to a gain on insurance proceeds related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant, which Enogex does not consider to be reflective of its ongoing performance.

Other Recent Developments

Texas Panhandle Gathering Divestiture

As previously reported in the Company's 2012 Form 10-K, on January 2, 2013, Enogex and one of its five largest customers entered into new agreements, effective January 1, 2013, relating to the customer's gathering and processing volumes on the Texas portion of Enogex's system. The effects of this new arrangement are (i) a fixed-fee processing agreement replaced the previous keep-whole agreement, (ii) the acreage dedicated by the customer to Enogex for gathering and processing in Texas was increased for an extended term and (iii) the sale by Enogex of certain gas gathering assets in the Texas Panhandle portion of Enogex's system to this customer for cash proceeds of approximately$35 million. Enogex recognized a pre-tax gain of$9.9 millionin the first quarter of 2013 in its natural gas gathering and processing segment from the sale of these assets which is included in Other Income in the Condensed Consolidated Statements of Income.

2013 Outlook

The Company's 2013consolidatedearnings guidanceis unchanged at approximately $335 million to $360 million of net income, or $3.35 to $3.60 per average diluted share. This guidance assumes normal weather for the remainder of the year, but excludes any impact from the formation of the Midstream Partnership or the operations of the CenterPoint midstream assets contributed to the Midstream Partnership. See the Company's 2012Form 10-K for the key factors and assumptions underlying its 2013 earnings guidance.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the threemonths endedMarch 31, 2013as compared to the same period in2012and the Company's consolidated financial position atMarch 31, 2013. Due to seasonal fluctuations and other factors, the Company'soperating results for the threemonths endedMarch 31, 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
	March 31,
(In millions except per share data)	2013		2012
Operating income	$	75.4	$	98.3
Net income attributable to OGE Energy	$	23.1	$	37.1
Basic average common shares outstanding	98.9		98.3
Diluted average common shares outstanding	99.4		98.8
Basic earnings per average common share attributable to OGE Energy common shareholders	$	0.23	$	0.38
Diluted earnings per average common share attributable to OGE Energy common shareholders	$	0.23	$	0.38
Dividends declared per common share	$	0.4175	$	0.3925

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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 (Loss) by Business Segment

	Three Months Ended
	March 31,
(In millions)	2013			2012
OG&E (Electric Utility)	$	52.9		$	39.8
Enogex (Natural Gas Midstream Operations)
Natural gas transportation and storage (A)	12.2			15.2
Natural gas gathering and processing	12.2			43.5
Other Operations (B)	(1.9		)	(0.2		)
Consolidated operating income	$	75.4		$	98.3

(A) During the third quarter of 2012,the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization.The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment 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
	March 31,
(Dollars in millions)	2013		2012
Operating revenues	$	455.5	$	426.7
Cost of goods sold	213.0		195.5
Gross margin on revenues	242.5		231.2
Other operation and maintenance	105.1		110.6
Depreciation and amortization	61.3		59.7
Taxes other than income	23.2		21.1
Operating income	52.9		39.8
Interest income	0.1		—
Allowance for equity funds used during construction	1.2		1.9
Other income	2.6		5.2
Other expense	0.5		0.7
Interest expense	31.4		30.9
Income tax expense	11.9		3.2
Net income	$	13.0	$	12.1
Operating revenues by classification
Residential	$	183.4	$	169.6
Commercial	105.6		99.9
Industrial	46.1		44.2
Oilfield	36.8		36.6
Public authorities and street light	41.6		39.4
Sales for resale	14.5		12.8
System sales revenues	428.0		402.5
Off-system sales revenues	2.1		8.9
Other	25.4		15.3
Total operating revenues	$	455.5	$	426.7
Megawatt-hour sales by classification (In millions)
Residential	2.2		1.9
Commercial	1.5		1.5
Industrial	0.9		1.0
Oilfield	0.8		0.8
Public authorities and street light	0.7		0.7
Sales for resale	0.3		0.3
System sales	6.4		6.2
Off-system sales	0.1		0.4
Total sales	6.5		6.6
Number of customers	801,194		792,065
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	3.409		2.937
Coal	2.286		2.246
Total fuel	2.827		2.500
Total fuel and purchased power	3.037		2.735
Degree days (A)
Heating - Actual	1,800		1,382
Heating - Normal	1,798		1,798
Cooling - Actual	4		61
Cooling - Normal	13		13

(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.

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Three Months Ended March 31, 2013 as Compared to Three Months Ended March 31, 2012

OG&E's operating incomeincreased$13.1 million, or32.9 percent, during thethreemonths endedMarch 31, 2013as compared to the same period in2012primarily due a higher gross margin and lower other operation and maintenance expense.

Gross Margin

Operating revenues were$455.5 millionduring thethreemonths endedMarch 31, 2013as compared to$426.7 millionduring the same period in2012, an increaseof$28.8 million, or6.7 percent. Cost of goods sold was$213.0 millionduring thethreemonths endedMarch 31, 2013as compared to$195.5 millionduring the same period in2012, an increaseof$17.5 million, or9.0 percent. Gross margin was$242.5 millionduring thethreemonths endedMarch 31, 2013as compared to$231.2 millionduring the same period in2012, an increaseof$11.3 million, or4.9 percent. The below factors contributed to the change in gross margin:

	$ Change
	(In millions)
Wholesale transmission revenue (A)	$	9.5
Quantity variance (primarily weather)	8.9
New customer growth	2.6
Non-residential demand and related revenues	0.5
Other	0.1
Price variance (B)	(10.3		)
Change in gross margin	$	11.3

(A) Increased primarily due to the inclusion of construction work in progress in transmission rates for specific FERC approved projects that previously accrued allowance for funds used during construction.

(B) Decreased due to lower rider revenues primarily from the Oklahoma storm recovery rider, the Oklahoma demand program rider, the timing of the Oklahoma rate increase and sales 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$146.4 millionduring thethreemonths endedMarch 31, 2013as compared to$143.1 millionduring the same period in2012, an increaseof$3.3 million, or2.3 percent, primarily due to higher natural gas generation 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$60.1 millionduring thethreemonths endedMarch 31, 2013as compared to$49.0 millionduring the same period in2012, an increaseof$11.1 million, or22.7 percent, primarily due to an increase in purchases in the energy imbalance service market. Transmission-related charges were$6.5 millionduring thethreemonths endedMarch 31, 2013as compared to$3.4 millionduring the same period in2012, an increaseof$3.1 million, or91.2 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 Enogex.

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Operating Expenses

Other operation and maintenance expense was$105.1 millionduring thethreemonths endedMarch 31, 2013as compared to$110.6 millionduring the same period in2012, a decreaseof$5.5 million, or5.0 percent. The below factors contributed to the change in other operation and maintenance expense:

	$ Change
	(In millions)
Employee benefits (A)	$	(3.1	)
Other marketing and sales expense (primarily lower demand-side management initiatives) (B)	(1.6		)
Salaries and wages (C)	(1.5		)
Allocations from holding company (primarily lower contract professional services)	(1.1		)
Contract professional services (B)(D)	(1.0		)
Other	(0.7		)
Administration and assessment fees (primarily SPP fees)	1.2
Capitalized labor	2.3
Change in other operation and maintenance expense	$	(5.5	)

(A) Decreased primarily due to a lower recoverable amount of pension expense allowed in the August 2012 rate case.

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

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

(D) Decreased primarily due to lower smart grid expenditures, which project was completed in late 2012.

Depreciation and amortization expense was$61.3 millionduring thethreemonths endedMarch 31, 2013as compared to$59.7 millionduring the same period in2012, an increaseof$1.6 million, or2.7 percent, primarily due to:

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

• additional assets being placed in service throughout 2012 and thethreemonths endedMarch 31, 2013, including the Sooner-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$23.2 millionduring thethreemonths endedMarch 31, 2013as compared to$21.1 millionduring the same period in2012, an increaseof$2.1 million, or10.0 percent, primarily due to higher ad valorem taxes.

Additional Information

Other Income.Other income was$2.6 millionduring thethreemonths endedMarch 31, 2013as compared to$5.2 millionduring the same period in2012, a decreaseof$2.6 million, or50.0 percent. Thedecreasein other income was primarily due toa decreasedmargin of$2.2 millionrecognized in the guaranteed flat bill program during thethreemonths endedMarch 31, 2013as a result of cooler weather.

Income Tax Expense.Income tax expense was$11.9 millionduring thethreemonths endedMarch 31, 2013as compared to$3.2 millionduring the same period in2012, an increaseof$8.7 million, primarily due toa reserve related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized and higher pre-tax income.

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Enogex (Natural Gas Midstream Operations)

Three Months Ended March 31, 2013	Natural Gas Transportation and Storage		Natural Gas Gathering and Processing		Eliminations			Total
(In millions)
Operating revenues	$	216.4	$	317.9	$	(70.0	)	$	464.3
Cost of goods sold	182.7		246.4		(69.9		)	359.2
Gross margin on revenues	33.7		71.5		(0.1		)	105.1
Other operation and maintenance	10.9		34.3		—			45.2
Depreciation and amortization	5.8		21.8		—			27.6
Taxes other than income	4.8		3.2		—			8.0
Operating income	$	12.2	$	12.2	$	(0.1	)	$	24.3

Three Months Ended March 31, 2012	Natural Gas Transportation and Storage		Natural Gas Gathering and Processing			Eliminations			Total
(In millions)
Operating revenues	$	169.5	$	304.5		$	(44.4	)	$	429.6
Cost of goods sold	131.8		217.9			(44.4		)	305.3
Gross margin on revenues	37.7		86.6			—			124.3
Other operation and maintenance	12.1		30.1			—			42.2
Depreciation and amortization	5.6		17.8			—			23.4
Impairment of assets	—		0.2			—			0.2
Gain on insurance proceeds	—		(7.5		)	—			(7.5		)
Taxes other than income	4.8		2.5			—			7.3
Operating income	$	15.2	$	43.5		$	—		$	58.7

Operating Data

	Three Months Ended
	March 31,
	2013			2012
Gathered volumes – TBtu/d	1.53			1.33
Incremental transportation volumes – TBtu/d (A)	0.63			0.52
Total throughput volumes – TBtu/d	2.16			1.85
Natural gas processed – TBtu/d	1.06			0.91
Condensate sold – million gallons	12			10
Average condensate sales price per gallon	$	1.97		$	2.17
NGLs sold (purchased) (keep-whole) – million gallons (B)	(74		)	37
NGLs sold (purchased) (for resale) – million gallons	235			155
NGLs sold (percent-of-liquids) – million gallons	5			6
NGLs sold (percent-of-proceeds) – million gallons	4			3
Total NGLs sold – million gallons	170			201
Average NGLs sales price per gallon	$	1.09		$	0.99
Average NGLs sales price per gallon (without ethane)	$	1.30		$	1.50
Average natural gas sales price per MMBtu	$	3.33		$	2.80

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

(B) Keep-whole NGLs purchased, rather than sold, in 2013 due to some producers electing ethane recovery while Enogex was physically rejecting ethane, which resulted in Enogex returning more NGLs to producers than extracted from processing.

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Three Months Ended March 31, 2013 as Compared to Three Months Ended March 31, 2012

Enogex's operating income decreased $34.4 million, or 58.6 percent, during the threemonths endedMarch 31, 2013 as compared to the same period in 2012. This decrease was primarily due to a lower gross margin, higher other operation and maintenance expense, higher depreciation and amortization expense and a gain on insurance proceeds during the threemonths endedMarch 31, 2012 related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant discussed below. The lower gross margin related to lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex’s five largest customers from keep-whole to fixed-feepartially offset byincreased gathering rates and volumes and inlet processing volumes associated with ongoing expansion projectsand the gas gathering assets acquired in August 2012. During the threemonths endedMarch 31, 2013, imbalance volume changes and realized margin on physical gas long/short positions decreased the gross margin by $0.4 million, net of corresponding imbalance and fuel tracker balances.

Other operation and maintenance expense increased $3.0 million, or 7.1 percent, primarily due to increasedpayroll and benefits costsdue to increased headcount to support business growth.

Depreciation and amortization expense increased $4.2 million, or 17.9 percent, primarily due to additional assets placed in service throughout 2012 and the threemonths endedMarch 31, 2013, including the gas gathering assets acquired in August 2012.

Gain on insurance proceeds, related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant, was $7.5 million during the threemonths endedMarch 31, 2012 with no corresponding item during the same period in 2013.

Natural Gas Transportation and Storage

The natural gas transportation and storage business contributed $33.7 million of Enogex's consolidated gross margin during the threemonths endedMarch 31, 2013 as compared to $37.7 million during the same period in 2012, a decrease of $4.0 million or 10.6 percent.  The transportation operations contributed $24.8 million of Enogex's consolidated gross margin during the threemonths endedMarch 31, 2013 as compared to $30.2 million during the same period in 2012.  The storage operations contributed $8.9 million of Enogex's consolidated gross margin during the threemonths endedMarch 31, 2013 as compared to $7.5 million during the same period in 2012. Gross margin decreased primarily due to:

• lower realized margin on sales of natural gas storage inventory, net of hedging activity, which decreased the gross margin by $2.1 million;

• lower transportation fees due to contract renewals with less favorable terms, which decreased the gross margin by $1.7 million;

• lower volumes and realized margin on sales of physical natural gas long positions associated with transportation operations, which decreased the gross margin by $1.3 million, net of imbalances and fuel tracker balances; and

• lower storage fees due to contract renewals with less favorable terms, which decreased the gross margin by $1.1 million.

These decreases in the natural gas transportation and storage gross margin were partially offset by lower of cost or market adjustments during the threemonths endedMarch 31, 2012 with no comparable item during the same period in 2013, which increased the gross margin by $5.0 million.

Other operation and maintenance expense for the natural gas transportation and storage business was $1.2 million, or 9.9 percent, lower during the threemonths endedMarch 31, 2013 as compared to the same period in 2012 primarily due to payroll and benefits costs allocated to the natural gas gathering and processing segment during the threemonths endedMarch 31, 2013.

Natural Gas Gathering and Processing

The natural gas gathering and processing business contributed $71.5 million of Enogex's consolidated gross margin during the threemonths endedMarch 31, 2013 as compared to $86.6 million during the same period in 2012, a decrease of $15.1 million, or 17.4 percent. The gathering operations contributed $36.8 million of Enogex's consolidated gross margin during the threemonths endedMarch 31, 2013 as compared to $30.8 million during the same period in 2012.  The processing operations contributed $34.7 million of Enogex's consolidated gross margin during the threemonths endedMarch 31, 2013 as compared to $55.8 million during the same period in 2012.

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During the threemonths endedMarch 31, 2013, Enogex realized a lower gross margin in its natural gas gathering and processing operations related to lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex’s five largest customers from keep-whole to fixed-fee effective January 1, 2013, which contributed to a decreased gross margin on keep-whole processing of $30.1 million. The decrease in the natural gas gathering and processing gross margin was partially offset by:

• an increased gross margin on fixed-fee contracts of $5.5 million primarily from the contract conversion discussed above; and

• an increase in gathering rates and volumes associated with ongoing expansion projects and gas gathering assets acquired in August 2012, which increased the gathering gross margin by $5.1 million and increased the percent-of-liquids and percent-of-proceeds gross margins by $1.8 million.

Other operation and maintenance expense for the natural gas gathering and processing business was $4.2 million, or 14.0 percent, higher during the threemonths endedMarch 31, 2013 as compared to the same period in 2012 primarily due to increasedpayroll and benefits costsdue to increased headcount to support business growth.

Enogex Consolidated Information

Other Income. Enogex's consolidated other income was $10.2 million during the threemonths endedMarch 31, 2013 as compared to $0.2 million during the same period in 2012, primarily due to a pre-tax gain of$9.9 millionrelated to the sale of certain gas gathering assets in the Texas Panhandle in January 2013 (see Note 2 of Notes to Condensed Consolidated Financial Statements).

Income Tax Expense. Enogex's consolidated income tax expense was $7.7 million during the threemonths endedMarch 31, 2013 as compared to $15.3 million during the same period in 2012, a decrease of $7.6 million, or 49.7 percent, primarily due to lower pre-tax income (net of noncontrolling interest) during the threemonths endedMarch 31, 2013 as compared to the same period in 2012.

Noncontrolling Interest. Enogex's net income attributable to noncontrolling interest was $5.2 million during the threemonths endedMarch 31, 2013 as compared to $10.4 million during the same period in 2012, a decrease of $5.2 million, or 50.0 percent, due to lower net income partially offset by the ArcLight group's increased ownership in Enogex Holdings as a result of the ArcLight group funding capital contributions at a disproportionate percentage to OGE Holdings throughout 2012.

Non-Recurring Items.During thethreemonths endedMarch 31, 2013, Enogex had an increase in net income of$6.1 millionrelated to a gain on the sale of certain gas gathering assets in the Texas Panhandle, as discussed above, which Enogex does not consider to be reflective of its ongoing performance.

During thethreemonths endedMarch 31, 2012, Enogex had an increase in net income of$4.6 milliondue to a gain on insurance proceeds related to the reimbursement of costs incurred to replace the damaged train at the Cox City natural gas processing plant, which Enogex does not consider to be reflective of its ongoing performance.

Non-GAAP Financial Measure

Enogex has included in this Form 10-Q the non-GAAP financial measure EBITDA.EBITDA is a supplemental non-GAAP financial measure used by external users of the Company's financial statements such as investors, commercial banks and others, to assess:

• the financial performance of Enogex's assets without regard to financing methods, capital structure or historical cost basis;

• Enogex's operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Enogex provides a reconciliation of EBITDA to net income attributable to Enogex Holdings, which Enogex considers to be its most directly comparable financial measure as calculated and presented in accordance with GAAP. The non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net income attributable to Enogex Holdings. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. EBITDA should not be considered in isolation or as a substitute for analysis of Enogex's results as reported under GAAP. Because EBITDA

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excludes some, but not all, items that affect net income and is defined differently by different companies in Enogex's industry, Enogex's definition of EBITDA may not be comparable to a similarly titled measure of other companies.

To compensate for the limitations of EBITDA as an analytical tool, Enogex believes it is important to review the comparable GAAP measure and understand the differences between the measures.

Reconciliation of EBITDA to net income attributable to Enogex Holdings

	Three Months Ended
	March 31,
(In millions)	2013		2012
Net income attributable to Enogex Holdings	$	24.8	$	49.5
Add:
Interest expense, net	8.1		7.6
Income tax expense (A)	0.1		0.1
Depreciation and amortization expense (B)	28.3		24.1
EBITDA	$	61.3	$	81.3
OGE Energy's portion	$	49.0	$	66.1

(A) As of November 1, 2010, Enogex Holdings' earnings are no longer subject to tax (other than Texas state margin taxes) and are taxable at the individual partner level.

(B) Includes amortization of certain customer-based intangible assets associated with the acquisition from Cordillera Energy Partners III, LLC in November 2011, which is included in gross margin for financial reporting purposes.

Off-Balance Sheet Arrangement

There have been no significant changes in the Company's off-balance sheet arrangement from those discussed in the Company's 2012Form 10-K.

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, Net, and Accrued Unbilled Revenues was$336.5 millionand$352.7 millionatMarch 31, 2013andDecember 31, 2012, respectively,a decreaseof$16.2 million, or4.6 percent, primarily due toa decrease in OG&E's billings to customers reflecting milder weather in March 2013 as compared to December 2012 partially offset by higher natural gas sales volumes at Enogex in March 2013 as compared to December 2012.

The balance of Accounts Payable was$409.5 millionand$396.7 millionatMarch 31, 2013andDecember 31, 2012, respectively,an increaseof$12.8 million, or3.2 percent, primarily due toan increase in accruals.

Cash Flows

	Three Months Ended
	March 31,						2013 vs. 2012
(In millions)	2013			2012			$ Change			% Change
Net cash provided from operating activities	$	59.2		$	120.3		$	(61.1	)	(50.8	)%
Net cash used in investing activities	(289.5		)	(295.1		)	5.6			(1.9	)%
Net cash provided from financing activities	235.6			171.8			63.8			37.1	%

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Operating Activities

Thedecrease of $61.1 million, or 50.8 percent, in net cash provided from operating activities during the three months endedMarch 31, 2013as compared to the same period in2012was primarily due to:

• fuel refunds at OG&E in the first quarter of 2013 as compared to fuel over recoveries in the same period in 2012; and

• lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex’s five largest customers from keep-whole to fixed-feepartially offset byincreased gathering rates and volumes and inlet processing volumes associated with ongoing expansion projectsand the gas gathering assets acquired in August 2012.

These decreases in net cash provided from operating activities were partially offset by an increase in cash received in the first quarter of 2013 from transmission revenue and higher usage.

Investing Activities

Thedecrease of $5.6 million, or 1.9 percent, in net cashused ininvesting activities during the three months endedMarch 31, 2013as compared to the same period in2012was primarily due to proceeds received from Enogex's sale of certain gas gathering assets in the Texas Panhandle partially offset by higher levels of capital expenditures in the first quarter of 2013 related to various transmission projects at OG&E and various gathering and processing projects at Enogex.

Financing Activities

Theincrease of $63.8 million, or 37.1 percent, in net cash provided from financing activities during the three months endedMarch 31, 2013as compared to the same period in2012 was primarily due an increase in short-term debt borrowingsduring thethreemonths endedMarch 31, 2013as compared to the same period in2012.

Future Capital Requirements and Financing Activities

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and Enogex. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.OGE Energy believes that the Midstream Partnership has, or will have access to, adequate liquidity and, therefore, no contributions are expected to be necessary to fund the capital expenditures of Enogex from the general partners.

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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 businesses) plus capital expenditures for known and committed projects.

(In millions)	2013		2014		2015		2016		2017
OG&E Base Transmission	$	65	$	50	$	50	$	50	$	50
OG&E Base Distribution	175		175		175		175		175
OG&E Base Generation	100		90		75		75		75
OG&E Other	15		15		15		15		15
Total OG&E Base Transmission, Distribution, Generation and Other	355		330		315		315		315
OG&E Known and Committed Projects:
Transmission Projects:
Balanced Portfolio 3E Projects (A)	205		25		—		—		—
SPP Priority Projects (B)	165		110		—		—		—
SPP Integrated Transmission Projects (C)	5		5		—		40		40
Total Transmission Projects	375		140		—		40		40
Other Projects:
Smart Grid Program	25		25		10		10		—
System Hardening	15		—		—		—		—
Environmental - low NOX burners	25		25		25		20		—
Total Other Projects	65		50		35		30		—
Total OG&E Known and Committed Projects	440		190		35		70		40
Total OG&E (D)	795		520		350		385		355
Enogex LLC Base Maintenance	50		55		55		55		55
Enogex LLC Known and Committed Projects:
Western Oklahoma/ Texas Panhandle Gathering Expansion (E)(F)	380		180		140		80		65
Other Gathering Expansion	25		15		10		10		10
Total Enogex LLC Known and Committed Projects	405		195		150		90		75
Total Enogex LLC (G)	455		250		205		145		130
OGE Energy	10		10		10		10		10
Total capital expenditures	$	1,260	$	780	$	565	$	540	$	495

(A) Balanced Portfolio 3E includes two projects to be built by OG&E and includes: (i) construction of 135 miles of transmission line from OG&E's Seminole substation in a northeastern direction to OG&E's Muskogee substation at an estimated cost of$175 millionfor OG&E, which is expected to be in service by late 2013 and (ii) construction of 96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southwestern direction to the Oklahoma/Texas Stateline to a companion transmission line to be built by Southwestern Public Service to its Tuco substation at an estimated cost of$115 millionfor OG&E, which is expected to be in service by mid-2014.

(B) The Priority Projects consist of several transmission projects, two of which have been assigned to OG&E. The 345 kilovolt projects include: (i) construction of 99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line to be built by Southwestern Public Service to its Hitchland substation in the Texas Panhandle at an estimated cost of$165 millionfor OG&E, which is expected to be in service by mid-2014 and (ii) construction of 77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border to be built by either Mid-Kansas Electric Company or another company assigned by Mid-Kansas Electric Company at an estimated cost of$150 millionto OG&E, which is expected to be in service by late 2014. OG&E began construction on the Hitchland project in November 2012 and expects to begin construction on the Kansas project in June 2013.

(C) On January 31, 2012, the SPP approved the Integrated Transmission Plan Near Term and Integrated Transmission Plan 10-year projects. These plans include two projects to be built by OG&E: (i) construction of 47 miles of transmission line from OG&E's Gracemont substation in a northwestern direction to a companion transmission line to be built by American Electric Power to its Elk City substation at an estimated cost of$75 millionfor OG&E, which is expected to be in service by early 2018, and (ii) construction of 126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation in a southeastern direction to OG&E's Cimarron substation and construction of a new substation on this transmission line,

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the Mathewson substation, at an estimated cost of$210 millionfor OG&E, which is expected to be in service by early 2021. On April 9, 2012, OG&E received a notice to construct these projects from the SPP. On June 26, 2012, OG&E responded to the SPP that OG&E will construct the projects discussed above and is moving forward with more detailed cost estimates that must be reviewed and approved by the SPP. OG&E and American Electric Power are currently in discussions regarding how much of the 94 mile Elk City to Gracemont transmission line will be built by OG&E and American Electric Power. American Electric Power has argued for a larger portion of such transmission line than the traditional 50 percent split. The capital expenditures related to these projects are presented in the summary of capital expenditures for known and committed projects above.

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

• Pollution control equipment related to controlling SO2 emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment.The SO2 emissions 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, which delays the timing of required implementation of the SO2 emissions standards in the rule. Neither the outcome of the challenge to the FIP nor the timing of any required capital expenditures can be predicted with any certainty at this time, but such capital expenditures could be significant.

• 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.

(E) Enogex is constructing a cryogenic processing plant in Custer County, Oklahoma, which is expected add 200 million cubic feet per day of natural gas processing capacity to Enogex's system, and is expected to be supported by the installation of 6,000 horsepower of inlet compression and four miles of transmission pipeline. This plant will be connected to the Enogex "super-header" gathering system and is expected to be in service by the end of the first quarter of 2014.

(F) In August 2012, Enogex completed construction of its cryogenic processing plant in Wheeler County, Texas, which added 200 million cubic feet per day of rich gas processing capacity to Enogex's system, and is supported by the installation of 9,400 horsepower of field compression, as well as 6,000 horsepower of inlet compression to facilitate additional flexibility in the operation of Enogex's "super-header" gathering system. The remainder of the inlet compression facilities is expected to be in service by the end of the second quarter 2013.

(G) These capital expenditures represent 100 percent of Enogex LLC's capital expenditures. As a result of the closing of the Midstream Partnership, the funding for the capital expenditures of Enogex will be the responsibility of the Midstream Partnership. OGE Energy believes that the Midstream Partnership has, or will have access to, adequate liquidity and, therefore, no contributions are expected to be necessary to fund the capital expenditures of Enogex from the general partners.

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.

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 the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, the Company would have been required to postnocash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position atMarch 31, 2013.  The Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

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Following the Company's March 14, 2013 announcement thatOGE 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 the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint, on March 15, 2013, Standard & Poor's Ratings Services placed the long-term senior unsecured rating of OGE Energy and OG&E on Credit Watch with positive implications which reflects the potential for a one-notch upgrade upon the successful formation and financing of the Midstream Partnership. Enogex's rating by Standard & Poor's Ratings Services remained unchanged with a stable outlook. All other security ratings as previously reported in the Company's 2012 Form 10-K were reaffirmed by the rating organizations.

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 andproceeds 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 March 31, 2013, the Company has revolving credit facilities totaling in the aggregate $1,550.0 million. These bank facilities can also be used asletter of credit facilities. The short-term debt balance was$707.0 millionand$430.9 millionatMarch 31, 2013andDecember 31, 2012, respectively. The weighted-average interest rate on short-term debt at March 31, 2013 was 0.37 percent.  The average balance of short-term debt during the three months ended March 31, 2013 was $557.7 million at a weighted-average interest rate of 0.38 percent. The increase in the short-term debt balance at March 31, 2013 as compared to the average balance of short-term debt during the three months ended March 31, 2013 was due to additional borrowings used to fund capital expenditures. The maximum month-end balance of short-term debt during the three months ended March 31, 2013 was $663.9 million. AtMarch 31, 2013, OG&E had$43.1 millionin outstanding commercial paper borrowings at a weighted average interest rate of0.32 percentand$2.1 millionin letters of credit at a weighted-average interest rate of0.53 percent. At March 31, 2013andDecember 31, 2012, Enogex had no outstanding borrowings under its revolving credit agreement. At March 31, 2013, borrowings under Enogex LLC's revolving credit agreement were classified as long-term debt in the Company's Condensed Consolidated Balance Sheets as it had a maturity date of December 13, 2016, along with its intent in utilizing its credit agreement.  At March 31, 2013, the Company had $840.9 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 March 31, 2013, the Company had $7.1 million in cash and cash equivalents.  See Note 11 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

Effective May 1, 2013, the Midstream Partnershipentered 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.

Expected Issuance of Long-Term Debt

OG&E expects to issue up to $250 million of long-term debt in the second quarter of 2013, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.

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

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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, fair value and cash flow hedges 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 transportation and storage segment and the natural gas gathering and processing 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. 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 14 and 15 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 and Enogex are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E's and Enogex's business activities in many ways, such as restricting the way they can handle or dispose of their wastes, requiring remedial action to mitigate pollution conditions that may be caused by their operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations 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 and Enogex believe that their 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.

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.

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The Oklahoma SIP included requirements for reducing emissions of NOX and SO2 from 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 SO2 control 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 SO2 control 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 SO2 BART 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 SO2 emission rate of0.06pounds per MMBtu 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 stay request on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the Tenth Circuit granted the stay request. The stay will remain in place until a decision on the petition for review is complete, which will delay the implementation of the regional haze rule in Oklahoma. The merits of the appeal have been fully briefed and oral argument occurred on March 6, 2013. Neither the outcome of the appeal nor the timing of any required expenditures for pollution control equipment can be predicted with any certainty at this time.

Notice of Violation

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. OG&E cannot predict at this time when or if litigation will be filed against it as a result of the notice of violation and, if litigation is filed, OG&E cannot predict the outcome of such litigation, but at this time has no reason to believe that it has not acted in compliance with the Federal Clean Air Act. 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 entered an agreement with the Sierra Club to toll the statute of limitations with respect to claims the Sierra Club may assert. The EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment and 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.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

Except as set forth below, the market risks set forth in Part II, Item 7A of the Company's 2012 Form 10-K appropriately represent, in all material respects, the market risks affecting the Company.

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Commodity Price Risk

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

A sensitivity analysis has been prepared to estimate the Company's exposure to commodity price risk. The Company's daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries.  Quoted market prices are not available for all of the Company's positions; therefore, the value of positions is a summation of the forecasted values calculated for each commodity based upon internally generated forward price curves.  Commodity price risk is estimated as the potential loss in fair value resulting from a hypothetical 20 percent decline in quoted market prices.  The result of this analysis, which may differ from actual results, reflects net commodity price risk to be $20.8 million at March 31, 2013. These amounts represent the Company's exposure, net of the ArcLight group's proportional share.

Item 4.  Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure.  As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company's management, including the chief executive officer and chief financial officer, of the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that the Company's disclosure controls and procedures are effective.

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

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

Reference is made to 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.

The Midstream Partnership may not be able to successfully integrate the operations of Enogex and CenterPoint.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributed100 percentof the equity interests inEnogex LLCto the Midstream Partnership. CenterPoint Energy Field Services, LLCwas converted into a Delaware limited partnership that became the Midstream Partnership. CenterPoint contributed to the Midstream Partnership its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC, CenterPoint Energy - Mississippi River Transmission, LLC, and certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute49 percentof its interest in Southeast Supply Header, LLC.  If the Midstream Partnership

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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 LLC or the Midstream Partnership, and therefore is not be able to cause or prevent certain actions by the Midstream Partnership.

Our Midstream Partnership 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 the Midstream Partnership to take actions that OGE Energy believes would be in our or the Midstream Partnership's best interests. Likewise, OGE Energy will be unable to prevent certain actions of the Midstream Partnership.

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 first 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
1/1/13 - 1/31/13	—		$	—	N/A	N/A
2/1/13 - 2/28/13	332	(A)	$	59.57	N/A	N/A
3/1/13 - 3/31/13	—		$	—	N/A	N/A

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

N/A - not applicable

Item 6.  Exhibits.

Exhibit No.	Description
2.01	Master Formation Agreement dated as of March 14, 2013 by and among CenterPoint Energy, Inc., OGE Energy Corp., Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC. (Filed as Exhibit 2.01 to OGE Energy's Form 8-K filed March 15, 2013 (File No. 1-12579) and incorporated by reference herein).
10.01	Form of Performance Unit Agreement under OGE Energy's 2008 Stock Incentive Plan.
10.02	Commitment Letter dated March 14, 2013 by and among CenterPoint Energy, Inc., Enogex LLC, Citigroup Global Markets Inc., UBS Loan Finance LLC and UBS Securities LLC relating to a $1,050,000,000 3 year unsecured term loan facility (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed March 15, 2013 (File No. 1-12579) and incorporation by reference herein).
10.03	Commitment Letter dated March 14, 2013 by and among CenterPoint Energy, Inc., Enogex LLC, Citigroup Global Markets Inc., UBS Loan Finance LLC and UBS Securities LLC relating to a $1,400,000,000 5 year unsecured revolving credit facility (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed March 15, 2013 (File No. 1-12579) and incorporation 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.

45

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)

May 2, 2013

46

EX-10.01

Exhibit 10.01

OGE ENERGY CORP.

FORM OF PERFORMANCE UNIT AGREEMENT

UNDER 2008 STOCK INCENTIVE PLAN

OGE Energy Corp. (the "Company") hereby awards, at target, to (_____) (the "Participant") (#) Performance Units pursuant to the OGE Energy Corp. 2008 Stock Incentive Plan (the "Plan"), the definitions and provisions of which are incorporated herein by reference.

The specific terms and conditions of the award are set forth hereinafter.

1. Performance Units and Award Cycle. Each Performance Unit represents and is equal to the value of one share of Company Common Stock. Subject to the provisions of the Plan, the Performance Units awarded to the Participant may not be sold, assigned, transferred, pledged, hypothecated or otherwise encumbered or disposed of during the award cycle established with respect thereto beginning on ______________ and ending on ______________ (the "Award Cycle").

2. Performance Goal Condition. The Performance Units are contingently awarded subject to the condition that the number of Performance Units, if any, earned by the Participant upon the expiration of the Award Cycle is dependent (in the manner hereinafter set forth) on the performance of Company's total shareholder return relative to the total shareholder return of all of the companies (the "S&P Companies") comprising the Standard and Poor's 1500 Utilities Index as of January 1, ____ and December 31, ____ (or their successors from a merger or other combination with another company listed in such Index, but excluding any company subject to a Business Combination, as hereinafter defined on December 31, ____). Total shareholder return ("TSR") for any company, including the Company, shall include both price appreciation (depreciation) and cash dividends, shall be calculated in the same manner that Standard and Poor's calculated total return as of _____________ and shall be measured by the company's total return that shareholders receive over the Award Cycle by investment at the first day of the Award Cycle.

The number of Performance Units earned is dependent on the performance ranking of the Company's total shareholder return for the Award Cycle, as set forth below (expressed in terms of the Company's position among the S&P Companies when ranked by total shareholder return for the Award Cycle):

COMPANY TSR PERCENTILE RANKING VS. S&P COMPANIES	PERCENT OF TARGET PERFORMANCE UNITS EARNED
__th percentile	200%
__th percentile	175%
__th percentile	150%
__th percentile	125%
__th percentile	100%
__th percentile	75%
__th percentile	50%
__th percentile	25%
Below __th percentile	0%

Performance Units earned for performance between the percentiles shown above will be determined by straight-line interpolation; provided, that, in all cases, the number of Performance Units which the Participant earns shall be a whole number (disregarding any fraction).

Any Performance Units awarded hereunder that the Participant does not earn at the end of the Award Cycle pursuant to the foregoing schedule shall be forfeited.

The provisions of this Section 2 shall not affect in any way any forfeiture under Section 4 below or Section 8(b) of the Plan or any provision regarding the earning of Performance Units at the 100% target level under Section 9 of the Plan upon the occurrence of a Change of Control.

For purposes of determining whether any of the S&P Companies is subject to a Business Combination on December 31, ____, a company shall be deemed subject to a Business Combination on December 31, ____, if such company is: (i) the subject of a tender offer or exchange offer by a third party seeking to acquire more than 20% of the outstanding voting securities of such company or (ii) a party to a merger, consolidation, share exchange or reorganization agreement or an agreement providing for the sale or disposition of all or substantially all of its assets.

3. Payout. Subject to Section 9 of the Plan, as soon as practicable following the end of the Award Cycle, but in no event later than the 15^th day of the third month thereafter, the Committee shall determine and certify to the number of Performance Units earned hereunder and, after the Committee certifies in writing the number of Performance Units earned and that all other material terms of the award have been satisfied, earned Performance Units, if any, will be paid to the Participant, or on the Participant's death, to the Participant's beneficiary under the Plan, by issuing a certificate for shares of Common Stock equal in number to the earned Performance Units (disregarding any fraction).

4. Forfeiture. All Performance Unit awards are subject to the terms and conditions of the Plan relating to Performance Units. If the Participant incurs a Termination of Employment for any reason on or before the end of the Award Cycle, all rights to or in respect of Performance Units awarded hereunder shall be forfeited except as provided in Section 8(b)(iii) or Section 9(a)(iii) of the Plan.

5. Acceptance of Award. By execution of this Agreement, the Participant accepts the award, acknowledges receipt of a copy of the Plan and represents that the Participant is familiar with the terms and provisions thereof and agrees to be bound thereby. Participant further agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee with respect to any questions arising under the Plan, including any calculation of, or in connection with, the total shareholder return of the Company or any other company for the Award Cycle.

6. Taxes and Other Matter.

(a)    By execution of this Agreement, the Participant agrees to pay all withholding and other taxes payable by the Participant with respect to Performance Units earned under this Agreement at such times and in such manner as the Company may request, and the Participant further agrees to comply with all Federal and State securities laws.

(b)    The Participant may elect, subject to approval of the Board of Directors or a committee composed of two or more non-employee directors within the meaning of Rule 16b-3(b)(3) of the Securities Exchange Act of 1934 or any successor provision thereto, to satisfy Participant's minimum tax withholding requirements under Federal, State and local laws and regulations thereunder, in whole or in part, by having the Company withhold shares having a fair market value equal to all or a portion of the amount so required to be withheld. The value of the shares to be withheld is to be based upon the same price of the shares that is utilized to determine the amount of withholding tax that the Participant owes. All elections under this Section 6(b) shall be (i) irrevocable, (ii) made in writing and signed by the Participant on the form prescribed by the Company and (iii) submitted to the Board of Directors prior to the date on which the Committee will determine the number of Performance Units earned hereunder or such earlier date as the Company shall prescribe.

7. Other Condition. The award of Performance Units evidenced by this Agreement shall be subject to delivery to the Company of an executed copy of this Agreement.

	OGE ENERGY CORP. ________________________________________________ Chairman of the Board, President and Chief Executive Officer
ACCEPTED AND AGREED TO this _____ day of _______________, ____. ______________________________                    Participant

OGE ENERGY CORP.

PERFORMANCE UNIT AGREEMENT

OGE Energy Corp. (the "Company") hereby awards, at target, to (____) (the "Participant") (#) Performance Units pursuant to the OGE Energy Corp. 2008 Stock Incentive Plan (the "Plan"), the definitions and provisions of which are incorporated herein by reference.

The specific terms and conditions of the award are set forth hereinafter.

1. Performance Units and Award Cycle. Each Performance Unit represents and is equal to the value of one share of Company Common Stock. Subject to the provisions of the Plan, the Performance Units awarded to the Participant may not be sold, assigned, transferred, pledged, hypothecated or otherwise encumbered or disposed of during the award cycle established with respect thereto beginning on ______________ and ending on ______________ (the "Award Cycle").

2. Performance Goal Condition. The Performance Units are contingently awarded subject to the condition that the number of Performance Units, if any, earned by the Participant upon the expiration of the Award Cycle is dependent (in the manner hereinafter set forth) on the Company's Average Earnings Per Share Growth during the Award Cycle. Average Earnings Per Share Growth shall mean the amount obtained by multiplying one-third times the percentage increase or decrease in the Company's earnings per share for the year ended December 31, ____ as compared to the Company's earnings per share for the year ended December 31, ____, of $____. Thus, for example, if the Company's earnings per share were $____ for the year ended December 31, ____, the Company's Average Earnings Per Share Growth would be ____% [1/3 x ($____/$____)]. For purposes of the foregoing, all percentages shall be calculated to the nearest one-hundredth of one percent and the Company's earnings per share for any year shall be the consolidated diluted earnings per average common share of the Company as reported on the Company's Consolidated Statement of Income for such year. The number of Performance Units earned for the Award Cycle shall be determined in accordance with the following chart:

COMPANY'S AVERAGE EARNINGS PER SHARE GROWTH	PERCENT OF TARGET PERFORMANCE UNITS EARNED
___%	200%
___%	180%
___%	160%
___%	140%
___%	120%
___%	100%
___%	87.5%
___%	75%
___%	62.5%
___%	50%
Below ___%	0%

Performance Units earned for performance between the percentiles shown above will be determined by straight-line interpolation; provided, that, in all cases, the number of Performance Units which the Participant earns shall be a whole number (disregarding any fraction).

Any Performance Units awarded hereunder that the Participant does not earn at the end of the Award Cycle pursuant to the foregoing chart shall be forfeited.

The provisions of this Section 2 shall not affect in any way any forfeiture under Section 4 below or Section 8(b) of the Plan or any provision regarding the earning of Performance Units at the 100% target level under Section 9 of the Plan upon the occurrence of a Change of Control.

3. Payout. Subject to Section 9 of the Plan, as soon as practicable following the end of the Award Cycle, but in no event later than the 15^th day of the third month thereafter, the Committee shall determine and certify to the number of Performance Units earned hereunder and, after the Committee certifies in writing the number of Performance Units earned and that other material terms of the award have been satisfied, earned Performance Units, if any, will be paid to the Participant, or on the Participant's death, to the Participant's beneficiary under the Plan, by issuing a certificate for shares of Common Stock equal in number to the earned Performance Units (disregarding any fraction).

4. Forfeiture. All Performance Unit awards are subject to the terms and conditions of the Plan relating to Performance Units. If the Participant incurs a Termination of Employment for any reason on or before the end of the Award Cycle, all rights to or in respect of Performance Units awarded hereunder shall be forfeited except as provided in Section 8(b)(iii) or Section 9(a)(iii) of the Plan.

5. Acceptance of Award. By execution of this Agreement, the Participant accepts the award, acknowledges receipt of a copy of the Plan and represents that the Participant is familiar with the terms and provisions thereof and agrees to be bound thereby. Participant further agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee with respect to any questions arising under the Plan, including any calculation of, or in connection with, earnings per share of the Company or any other company for the any period.

6. Taxes and Other Matter.

(a)    By execution of this Agreement, the Participant agrees to pay all withholding and other taxes payable by the Participant with respect to Performance Units earned under this Agreement at such times and in such manner as the Company may request, and the Participant further agrees to comply with all Federal and State securities laws.

(b)    The Participant may elect, subject to approval of the Board of Directors or a committee composed of two or more non-employee directors within the meaning of Rule 16b-3(b)(3) of the Securities Exchange Act of 1934 or any successor provision thereto, to satisfy Participant's minimum tax withholding requirements under Federal, State and local laws and regulations thereunder, in whole or in part, by having the Company withhold shares having a fair market value equal to all or a portion of the amount so required to be withheld. The value of the shares to be withheld is to be based upon the same price of the shares that is utilized to determine the amount of withholding tax that the Participant owes. All elections under this Section 6(b) shall be (i) irrevocable, (ii) made in writing and signed by the Participant on the form prescribed by the Company and (iii) submitted to the Board of Directors prior to the date on which the Committee will determine the number of Performance Units earned hereunder or such earlier date as the Company shall prescribe.

7. Other Condition. The award of Performance Units evidenced by this Agreement shall be subject to delivery to the Company of an executed copy of this Agreement.

	OGE ENERGY CORP. ________________________________________________ Chairman of the Board, President and Chief Executive Officer
ACCEPTED AND AGREED TO this _____ day of _______________, ____. ______________________________                    Participant

OGE ENERGY CORP.

PERFORMANCE UNIT AGREEMENT

OGE Energy Corp. (the "Company") hereby awards, at target, to (____) (the "Participant") (#) Performance Units pursuant to the OGE Energy Corp. 2008 Stock Incentive Plan (the "Plan"), the definitions and provisions of which are incorporated herein by reference.

The specific terms and conditions of the award are set forth hereinafter.

1. Performance Units and Award Cycle. Each Performance Unit represents and is equal to $____ per unit. Subject to the provisions of the Plan, the Performance Units awarded to the Participant may not be sold, assigned, transferred, pledged, hypothecated or otherwise encumbered or disposed of during the award cycle established with respect thereto beginning on _____________ and ending on _______________ (the "Award Cycle").

2. Performance Goal Condition. The Performance Units are contingently awarded subject to the condition that the number of Performance Units, if any, earned by the Participant upon the expiration of the Award Cycle is dependent (in the manner hereinafter set forth) on Enogex's Average EBITDA Per Unit Growth during the Award Cycle. Enogex's Average EBITDA Per Unit Growth shall mean the amount obtained by multiplying one-third times the percentage increase or decrease in Enogex EBITDA Per Unit for the year ended December 31, ____ as compared to Enogex EBITDA Per Unit for the year ended December 31, ____, of $____. Thus, for example, if Enogex EBITDA Per Unit were $____ for the year ended December 31, ____, Enogex's Average EBITDA Per Unit Growth would be ___% [1/3 x ($____/$____)]. For purposes of the foregoing: (i) all percentages shall be calculated to the nearest one-hundredth of one percent, (ii) Enogex EBITDA shall mean, as shown on the consolidated income statement of Enogex LLC unless otherwise stated, net income from continuing operations plus interest expense, income taxes, depreciation expense, and amortization expense (including any amortization of acreage dedication fees not presented under the amortization caption under GAAP), less interest income, and (iii) Enogex EBITDA Per Unit shall mean Enogex EBITDA divided by the weighted average number of outstanding membership units of Enogex Holdings LLC for the period in question. The number of Performance Units earned for the Award Cycle shall be determined in accordance with the following chart:

ENOGEX'S AVERAGE EBITDA PER UNIT GROWTH	PERCENT OF TARGET PERFORMANCE UNITS EARNED
___%	200%
___%	180%
___%	160%
___%	140%
___%	120%
___%	100%
___%	87.5%
___%	75%
___%	62.5%
___%	50%
Below ___%	—%

Performance Units earned for performance between the percentiles shown above will be determined by straight-line interpolation; provided, that, in all cases, the number of Performance Units which the Participant earns shall be a whole number (disregarding any fraction).

Any Performance Units awarded hereunder that the Participant does not earn at the end of the Award Cycle pursuant to the foregoing chart shall be forfeited.

The provisions of this Section 2 shall not affect in any way any forfeiture under Section 4 below or Section 8(b) of the Plan or any provision regarding the earning of Performance Units at the 100% target level under Section 9 of the Plan upon the occurrence of a Change of Control.

3. Payout. Subject to Section 9 of the Plan, as soon as practicable following the end of the Award Cycle, but in no event later than the 15^th day of the third month thereafter, the Committee shall determine and certify to the number of Performance Units earned hereunder and, after the Committee certifies in writing the number of Performance Units earned and that other material terms of the award have been satisfied, earned Performance Units, if any, will be paid to the Participant, or on the Participant's death, to the Participant's beneficiary under the Plan in cash, by paying an amount equal to the number of earned Performance Units (disregarding any fraction) multiplied by $____.

4. Forfeiture. All Performance Unit awards are subject to the terms and conditions of the Plan relating to Performance Units. If the Participant incurs a Termination of Employment for any reason on or before the end of the Award Cycle, all rights to or in respect of Performance Units awarded hereunder shall be forfeited except as provided in Section 8(b)(iii) or Section 9(a)(iii) of the Plan.

5. Acceptance of Award. By execution of this Agreement, the Participant accepts the award, acknowledges receipt of a copy of the Plan (a copy of which is attached as Annex I), and represents that the Participant is familiar with the terms and provisions thereof and agrees to be bound thereby. Participant further agrees to accept as binding, conclusive and final all decisions or interpretations of the Committee with respect to any questions arising under the Plan, including any calculation of, or in connection with, Enogex's Average EBITDA Per Unit Growth. Participant further agrees that, if certain events occur (which events are referenced in resolutions adopted by the Committee on the date this award of Performance Units was approved by the Committee) during the Award Cycle, then the Performance Goal of Enogex's Average EBITDA Per Unit Growth in Section 2 above shall be changed so that the Performance Goal for the Performance Units evidenced by this Agreement are based 50% on total shareholder return (which is the Performance Goal for other Performance Units being awarded to Participant on this date) and 50% on OGE Energy's Average Earnings Per Share Growth (which is a Performance Goal for Performance Units being awarded to other participants in the Plan on this date), with the payout, if any, of each of these Performance Goals being made in OGE Energy Common Stock.

6. Taxes and Other Matter. By execution of this Agreement, the Participant agrees to pay all withholding and other taxes payable by the Participant with respect to Performance Units earned under this Agreement at such times and in such manner as the Company may request, and the Participant further agrees to comply with all Federal and State securities laws.

7. Other Condition. The award of Performance Units evidenced by this Agreement shall be subject to delivery to the Company of an executed copy of this Agreement.

	OGE ENERGY CORP. ________________________________________________ Chairman of the Board, President and Chief Executive Officer
ACCEPTED AND AGREED TO this _____ day of _______________, ____. ______________________________                    Participant

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: May 2, 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: May 2, 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 endedMarch 31, 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.

May 2, 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, 2011, 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 225,000,000 shares of common stock, par value $0.01 per share, of which 99,116,609 shares were outstanding on March 31, 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's 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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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) Reclassifications out of AOCI (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Gains (Losses) on Cash Flow Hedges, Amount Reclassified from Accumulated OCI	$ 0
Amortization of Defined Benefit Pension Items, Amounts Reclassified from Accumulated OCI, Before Tax	(1.3)
Amortization of Defined Benefit Pension Items, Amount Reclassified from Accumulated OCI, Tax	(0.4)
Amortization of Defined Benefit Pension Items, Amount Reclassified from Accumulated OCI, Net of Tax	(0.9)
Amortization of Defined Benefit Pension Items, Amount Reclassified from Accumulated OCI, Noncontrolling Interest	(0.1)
Amortization of Defined Benefit Pension Items, Amount Reclassified from Accumulated OCI, Net of Tax and Noncontrolling Interest	(0.8)
Amortization of Defined Benefit Postretirement Items, Amount Reclassified from Accumulated OCI, Before Tax	0
Amounts Reclassified from Accumulated OCI, Net of Tax and Noncontrolling Interest	(0.8)
Commodity Contract [Member]
Gains (Losses) on Cash Flow Hedges, Amount Reclassified from Accumulated OCI	0.2
Interest Rate Swap [Member]
Gains (Losses) on Cash Flow Hedges, Amount Reclassified from Accumulated OCI	(0.2)
Actuarial Gains (Losses) [Member]
Amortization of Defined Benefit Pension Items, Amounts Reclassified from Accumulated OCI, Before Tax	(1.3)	[1]
Prior Service Cost [Member]
Amortization of Defined Benefit Postretirement Items, Amount Reclassified from Accumulated OCI, Before Tax	0.8	[1]
Actuarial Gains (Losses) [Member]
Amortization of Defined Benefit Postretirement Items, Amount Reclassified from Accumulated OCI, Before Tax	$ (0.8)	[1]

[1] These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 12 for additional information).

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Short-Term Debt and Credit Facilities (Details) (USD $) In Millions, unless otherwise specified						3 Months Ended
	Mar. 31, 2013		Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2013 OGE Energy [Member]		Mar. 31, 2013 OG&E [Member]		May 01, 2013 Midstream Partnership [Member]	Mar. 31, 2013 Enogex Llc [Member]
Line of Credit Facility [Line Items]
Short-term debt	$ 707.0		$ 430.9
Line of Credit Facility [Abstract]
Aggregate Commitment	1,550.0					750.0	[1]	400.0		1,400.0	400.0	[2]
Amount Outstanding	709.1	[3]				663.9	[1],[3]	45.2	[3],[4]		0	[2],[3]
Cash	7.1		1.8	1.6	4.6
Total	1,557.1
Weighted Average Interest Rate	0.38%					0.38%	[1],[5]	0.33%	[4],[5]		0.00%	[2],[5]
Maturity						Dec. 13, 2016		Dec. 13, 2016
Letters of Credit Outstanding, Amount								2.1
Commercial Paper								43.1
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 March 31, 2013, there was $663.9 million in outstanding commercial paper borrowings.

[2] This bank facility was available to provide revolving credit borrowings for Enogex LLC. Effective May 1, 2013, the Midstream Partnership 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.

[3] Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2013.

[4] This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At March 31, 2013, there was $43.1 million in outstanding commercial paper borrowings and $2.1 million in letters of credit.

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

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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
	Mar. 31, 2013	Mar. 31, 2012
Enogex [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Other Comprehensive Income	$ 0	$ 0.3
Amount Reclassifed from Accumulated Other Comprehensive Income (Loss) into Income	0	5.0
Amount Recognized in Income	0	0
Enogex [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Income	(0.3)	(2.0)
Enogex [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Other Comprehensive Income	0	0.3
Amount Reclassifed from Accumulated Other Comprehensive Income (Loss) into Income	0.2	5.2
Amount Recognized in Income	0	0
Enogex [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Income	(0.3)	0.4
Enogex [Member] | Sales [Member] | Natural gas [Member] | Physical [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount Recognized in Income		(2.4)
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	0
Amount Reclassifed from Accumulated Other Comprehensive Income (Loss) into Income	(0.2)	(0.2)
Amount Recognized in Income	0	0
Maximum [Member] | Enogex [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Additional Collateral, Aggregate Fair Value	$ 0

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Retirement Plans and Postretirement Benefit Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net Periodic Benefit Cost	$ 6.6		$ 7.7
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	5.0		4.5
Interest cost	6.6		7.5
Expected return on plan assets	(12.3)		(11.5)
Amortization of net loss	6.2		5.9
Amortization of unrecognized prior service cost	0.5	[1]	0.6	[1]
Net Periodic Benefit Cost	6.0	[2]	7.0	[2]
Capitalized Portion of Net Periodic Benefit Cost	1.1		1.5
Restoration of Retirement Income Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	0.3		0.3
Interest cost	0.1		0.1
Expected return on plan assets	0		0
Amortization of net loss	0.1		0.1
Amortization of unrecognized prior service cost	0.1	[1]	0.2	[1]
Net Periodic Benefit Cost	0.6	[2]	0.7	[2]
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	1.2		1.0
Interest cost	2.6		3.0
Expected return on plan assets	(0.6)		(0.8)
Amortization of transition obligation	0		0.7
Amortization of net loss	5.3		5.1
Amortization of unrecognized prior service cost	(4.1)	[1]	(4.1)	[1]
Net Periodic Benefit Cost	4.4	[3]	4.9	[3]
Capitalized Portion of Net Periodic Benefit Cost	0.8		1.0
OKLAHOMA | Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements	1.9		2.9
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements	$ 0.1		$ 0.4

[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 $6.6 million and $7.7 million of net periodic benefit cost recognized during the three months ended March 31, 2013 and 2012, respectively, OG&E recognized an increase in pension expense during the three months ended March 31, 2013 and 2012 of $1.9 million and $2.9 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 $4.4 million and $4.9 million of net periodic benefit cost recognized during the three months ended March 31, 2013 and 2012, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended March 31, 2013 and 2012 of $0.1 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).

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Derivative Instruments and Hedging Activities, Quantitative Disclosures Related to Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Enogex [Member] | Natural gas [Member]
Derivative [Line Items]
Percent of Contract with Durations of One Year or Less	94.20%
Percent of Contracts With Durations of More Than One Year and Less Than Two Years	4.20%
Percent of Contracts Having a Duration of More Than Two Years	1.60%
Fixed Swaps/Futures [Member] | Enogex [Member] | Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (MMBtu's)	100,000	[1],[2]
Fixed Swaps/Futures [Member] | Enogex [Member] | Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (MMBtu's)	100,000	[1],[2]
Basis Swaps [Member] | Enogex [Member] | Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (MMBtu's)	11,600,000	[1],[2]
Basis Swaps [Member] | Enogex [Member] | Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (MMBtu's)	5,200,000	[1],[2]
Fair Value Hedging [Member]
Derivative [Line Items]
Fair Value Hedges, Net	$ 0		$ 0
Physical [Member] | Enogex [Member] | Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Sales [Member]
Derivative [Line Items]
Gross Notional Volume (MMBtu's)	71,300,000	[1],[2],[3],[4]
Physical [Member] | Enogex [Member] | Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Purchases [Member]
Derivative [Line Items]
Gross Notional Volume (MMBtu's)	7,000,000	[1],[2],[3],[4]

[1] 94.2 percent of the natural gas contracts have durations of one year or less, 4.2 percent have durations of more than one year and less than two years and 1.6 percent have durations of more than two years.

[2] Natural gas in MMBtu's.

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

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

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Retirement Plans and Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 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						Three Months Ended
	March 31,						March 31,
(In millions)	2013 (B)			2012 (B)			2013 (B)		2012 (B)
Service cost	$	5.0		$	4.5		$	0.3	$	0.3
Interest cost	6.6			7.5			0.1		0.1
Expected return on plan assets	(12.3		)	(11.5		)	—		—
Amortization of net loss	6.2			5.9			0.1		0.1
Amortization of unrecognized prior service cost (A)	0.5			0.6			0.1		0.2
Net periodic benefit cost	$	6.0		$	7.0		$	0.6	$	0.7

(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$6.6 millionand$7.7 millionof net periodic benefit cost recognizedduring thethreemonths endedMarch 31, 2013and2012, respectively, OG&E recognized an increase in pension expense during thethreemonths endedMarch 31, 2013and2012of$1.9 millionand$2.9 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
	March 31,
(In millions)	2013 (B)			2012 (B)
Service cost	$	1.2		$	1.0
Interest cost	2.6			3.0
Expected return on plan assets	(0.6		)	(0.8		)
Amortization of transition obligation	—			0.7
Amortization of net loss	5.3			5.1
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)
Net periodic benefit cost	$	4.4		$	4.9

(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$4.4 millionand$4.9 millionof net periodic benefit cost recognizedduring thethreemonths endedMarch 31, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthethreemonths endedMarch 31, 2013and2012of$0.1 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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Commitments and Contingencies (Details) (USD $)		7 Months Ended	10 Months Ended
	Mar. 31, 2013	Oct. 31, 2013 OG&E minimum fuel purchase commitments [Member]	Oct. 31, 2013 OG&E minimum fuel purchase commitments [Member]
Long-term Purchase Commitment [Line Items]
Percentage of OG&E's projected 2013 requirements		55.80%	26.10%
Potential Penalty Under the Federal Clean Air Act	$ 37,500

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 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)	March 31, 2013		December 31, 2012
Regulatory Assets
Current
Crossroads wind farm rider under recovery (A)	$	13.4	$	14.9
Oklahoma demand program rider under recovery (A)	9.4		9.2
Fuel clause under recoveries	0.4		—
Other (A)	7.6		2.9
Total Current Regulatory Assets	$	30.8	$	27.0
Non-Current
Benefit obligations regulatory asset	$	364.1	$	370.6
Income taxes recoverable from customers, net	54.9		54.7
Smart Grid	42.9		42.8
Unamortized loss on reacquired debt	12.7		13.0
Deferred storm expenses	12.3		12.7
Deferred pension expenses	3.4		4.5
Other	12.3		12.3
Total Non-Current Regulatory Assets	$	502.6	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	81.6	$	109.2
Smart Grid rider over recovery (B)	21.6		24.1
Other (B)	6.5		7.8
Total Current Regulatory Liabilities	$	109.7	$	141.1
Non-Current
Accrued removal obligations, net	$	219.4	$	218.2
Deferred pension credits	14.9		17.7
Pension tracker	11.2		9.2
Total Non-Current Regulatory Liabilities	$	245.5	$	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 thethreemonths endedMarch 31, 2013and2012.

	Three Months Ended
	March 31,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled	(0.1		)	—
Accretion expense	0.6			0.4
Revisions in estimated cash flows (A)	—			26.7
Balance at March 31	$	54.5		$	51.9

(A) Due to changes to OG&E's asset retirement obligations related to its wind farms due to a change 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 thethreemonths endedMarch 31, 2013. At both March 31, 2013 and December 31, 2012, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka. 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)	0.9			—		0.5			(0.5		)	(0.1		)	0.1			0.1			0.8
Balance at March 31, 2013	$	(48.4	)	$	0.1	$	(15.2	)	$	6.7		$	—		$	(0.4	)	$	(8.9	)	$	(48.3	)

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 thethreemonths endedMarch 31, 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
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)	$	(1.3	)	(A)
	(1.3		)	Total before tax
	(0.4		)	Tax benefit
	(0.9		)	Net of tax
	(0.1		)	Noncontrolling interest
	$	(0.8	)	Net of tax and noncontrolling interest
Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.8	)	(A)
Prior service cost	0.8			(A)
	—			Total before tax
Total reclassifications for the period	$	(0.8	)	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 12 for additional information).

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Income Taxes Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
FIN 48 [Member]
Income Tax Reconciliation, Tax Contingencies, State and Local	$ 7.8
FIN 48 reserve, net of tax [Member]
Income Tax Reconciliation, Tax Contingencies, State and Local	$ 5.1

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Noncontrolling Interests Contributions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
OGE Holdings [Member]
Noncontrolling Interest [Line Items]
Ownership percentage, OGE Holdings	79.90%
Contributions Toward Meeting 2013 Capital Requirements	$ 0
ArcLight group [Member]
Noncontrolling Interest [Line Items]
Contributions from noncontrolling interest partner	0
Atoka [Member]
Noncontrolling Interest [Line Items]
Contributions from noncontrolling interest partner	$ 0

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Summary of Significant Accounting Policies Asset Retirement Obligation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 54.0	$ 24.8
Liabilities settled	(0.1)	0
Accretion expense	0.6	0.4
Revisions in estimated cash flows	0	26.7	[1]
Balance at March 31	$ 54.5	$ 51.9

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

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Common Equity Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Equity [Abstract]
Net Income Attributable to OGE Energy	$ 23.1	$ 37.1
Basic Average Common Shares Outstanding	98.9	98.3
Contingently Issuable Shares (Performance Units)	0.5	0.5
Diluted Average Common Shares Outstanding	99.4	98.8
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.23	$ 0.38
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.23	$ 0.38
Anti-dilutive shares excluded from earnings per share calculation	0	0

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Derivative Instruments and Hedging Activities, Balance Sheet Presentation Related to Derivative Instruments (Details) (Enogex [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Assets	$ 0.5	[1]	$ 5.5	[2]
Liabilities	0.6	[1]	5.5	[2]
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets			0
Liabilities			0.5
Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Assets			0
Liabilities			0.5
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets	0.5		5.5
Liabilities	0.6		5.0
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets			0.1
Liabilities			0
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Fixed Swaps/Futures [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Assets	0.1		5.0
Liabilities	0.2		4.7
Not Designated as Hedging Instrument [Member] | Natural gas [Member] | Physical [Member] | Current PRM [Member]
Derivatives, Fair Value [Line Items]
Assets	0.4		0.4
Liabilities	$ 0.4		$ 0.3

[1] See Note 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at March 31, 2013.

[2] See Note 5 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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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 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 three business segments:  (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing.  All significant intercompany transactions have been eliminated in consolidation.

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.

Enogex is a provider of integrated natural gas midstream services.Enogex is engaged in the business of gathering, processing, transporting and storing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.Enogex's operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.AtMarch 31, 2013, OGE Energy indirectly owns a79.9 percentmembership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company.  At March 31, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements as OGE Energy had a controlling financial interest over the operations of Enogex Holdings.  Also, at March 31, 2013, Enogex LLC held a 50 percent ownership interest in Atoka.  At March 31, 2013, the Company consolidated Atoka in its Condensed Consolidated Financial Statements as Enogex acted as the managing member of Atoka and had control over the operations of Atoka.

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 the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint. This transaction closed on May 1, 2013.Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight groupindirectlycontributedEnogex LLCto the Midstream Partnershipand CenterPoint Energy, Inc. contributed its midstream natural gas business to the Midstream Partnership.At May 1, 2013, OGE Energy holds28.5 percentof the limited partners interests, CenterPoint holds58.3 percentof the limited partner interests and the ArcLight group holds13.2 percentof the limited partner interests in the Midstream Partnership. The general partner of the Midstream Partnership 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 Energy deconsolidated its interest in Enogex LLC and will account for its interest in the Midstream Partnership under the equity method of accounting.For additional information regarding the Midstream Partnership, see Note 3.

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 atMarch 31, 2013andDecember 31, 2012and the results of its operations and cash flows for the threemonths endedMarch 31, 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 threemonths endedMarch 31, 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)	March 31, 2013		December 31, 2012
Regulatory Assets
Current
Crossroads wind farm rider under recovery (A)	$	13.4	$	14.9
Oklahoma demand program rider under recovery (A)	9.4		9.2
Fuel clause under recoveries	0.4		—
Other (A)	7.6		2.9
Total Current Regulatory Assets	$	30.8	$	27.0
Non-Current
Benefit obligations regulatory asset	$	364.1	$	370.6
Income taxes recoverable from customers, net	54.9		54.7
Smart Grid	42.9		42.8
Unamortized loss on reacquired debt	12.7		13.0
Deferred storm expenses	12.3		12.7
Deferred pension expenses	3.4		4.5
Other	12.3		12.3
Total Non-Current Regulatory Assets	$	502.6	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	81.6	$	109.2
Smart Grid rider over recovery (B)	21.6		24.1
Other (B)	6.5		7.8
Total Current Regulatory Liabilities	$	109.7	$	141.1
Non-Current
Accrued removal obligations, net	$	219.4	$	218.2
Deferred pension credits	14.9		17.7
Pension tracker	11.2		9.2
Total Non-Current Regulatory Liabilities	$	245.5	$	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.

Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during thethreemonths endedMarch 31, 2013and2012.

	Three Months Ended
	March 31,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled	(0.1		)	—
Accretion expense	0.6			0.4
Revisions in estimated cash flows (A)	—			26.7
Balance at March 31	$	54.5		$	51.9

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

Accumulated Other Comprehensive Income (Loss)

In February 2013, the Financial Accounting Standards Board issued "Comprehensive Income: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." The new standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, the new standard requires an entity to present significant amounts reclassified out of accumulated other comprehensive income by the respective line items in net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The Company adopted the new standard effective January 1, 2013 and these disclosures have been included below.

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to OGE Energy during thethreemonths endedMarch 31, 2013. At both March 31, 2013 and December 31, 2012, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka. 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)	0.9			—		0.5			(0.5		)	(0.1		)	0.1			0.1			0.8
Balance at March 31, 2013	$	(48.4	)	$	0.1	$	(15.2	)	$	6.7		$	—		$	(0.4	)	$	(8.9	)	$	(48.3	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during thethreemonths endedMarch 31, 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
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)	$	(1.3	)	(A)
	(1.3		)	Total before tax
	(0.4		)	Tax benefit
	(0.9		)	Net of tax
	(0.1		)	Noncontrolling interest
	$	(0.8	)	Net of tax and noncontrolling interest
Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.8	)	(A)
Prior service cost	0.8			(A)
	—			Total before tax
Total reclassifications for the period	$	(0.8	)	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 12 for additional information).

Reclassifications

As discussed in Note 13, during the third quarter of 2012, the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization.The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented to conform to the 2013 presentation.

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Noncontrolling Interests Distributions Made to Partners (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
OGE Holdings [Member]
Distribution Made to Partners [Line Items]
Distributions to partners	$ 10.0
ArcLight group [Member]
Distribution Made to Partners [Line Items]
Distributions to partners	2.5
Enogex Holdings [Member]
Distribution Made to Partners [Line Items]
Distributions to partners	12.5
Atoka [Member]
Distribution Made to Partners [Line Items]
Distributions to partners	$ 0

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Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 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 thethreemonths endedMarch 31, 2013 and 2012related to the Company's performance units and restricted stock.

	Three Months Ended
	March 31,
(In millions)	2013		2012
Performance units
Total shareholder return	$	2.0	$	1.8
Earnings per share	0.6		0.7
Total performance units	2.6		2.5
Restricted stock	0.1		0.2
Total compensation expense	$	2.7	$	2.7
Income tax benefit	$	1.0	$	1.1

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

The following table summarizes the activity of the Company's stock-based compensation during thethreemonths endedMarch 31, 2013.

	Units/Shares	Fair Value
Grants
Performance units (Total shareholder return)	156,974	$	58.61
Performance units (Earnings per share)	37,094	$	53.45
Restricted stock	2,970	$	59.41
Conversions
Performance units (Total shareholder return) (A)	188,631	N/A
Performance units (Earnings per share) (A)	62,880	N/A

(A) Performance units were converted based on a payout ratio of200 percentof the target number of performance units granted in February2010and are included in the258,260 and 62,632shares of common stock issued during thethreemonths endedMarch 31, 2013as discussed above.

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Derivative Instruments and Hedging Activities (Tables)

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

At March 31, 2013, the Company had the following derivative instruments that were not designated as hedging instruments.

(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	7.0	71.3
Fixed Swaps/Futures	0.1	0.1
Basis Swaps	5.2	11.6

(A) Natural gas in MMBtu's.  

(B) 94.2 percent of the natural gas contracts have durations of one year or less, 4.2 percenthave durations of more than one year and less than two years and 1.6 percenthave durations of more than two years.

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

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

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

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet atMarch 31, 2013are as follows:

		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	0.1	$	0.2
Physical Purchases/Sales	Current PRM	0.4		0.4
Total		$	0.5	$	0.6
Total Gross Derivatives (A)		$	0.5	$	0.6

(A) See Note 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet atMarch 31, 2013.

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet atDecember 31, 2012are 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 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet atDecember 31, 2012.

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

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months endedMarch 31, 2013.

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		$	—
Interest Rate Swap	—		(0.2		)	—
Total	$	—	$	—		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.3	)
Total	$	(0.3	)

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months endedMarch 31, 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	$	0.3	$	5.2		$	—
Interest Rate Swap	—		(0.2		)	—
Total	$	0.3	$	5.0		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(2.4	)
Natural Gas Financial Futures/Swaps	0.4
Total	$	(2.0	)

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Report of Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$ 901.4	$ 840.7
Cost of goods sold	553.0	485.3
Gross margin on revenues	348.4	355.4
Other operation and maintenance	148.0	147.6
Depreciation and amortization	91.9	86.6
Impairment of assets	0	0.2
Gain on insurance proceeds	0	(7.5)
Taxes other than income	33.1	30.2
Operating income (loss)	75.4	98.3
Total assets	9,981.8	9,074.5	9,922.2
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	455.5	426.7
Cost of goods sold	213.0	195.5
Gross margin on revenues	242.5	231.2
Other operation and maintenance	105.1	110.6
Depreciation and amortization	61.3	59.7
Impairment of assets		0
Gain on insurance proceeds		0
Taxes other than income	23.2	21.1
Operating income (loss)	52.9	39.8
Total assets	7,138.4	6,632.8
Transportation and Storage [Member]
Segment Reporting Information [Line Items]
Operating revenues	216.4	169.5
Cost of goods sold	182.7	131.8
Gross margin on revenues	33.7	37.7
Other operation and maintenance	10.9	12.1
Depreciation and amortization	5.8	5.6
Impairment of assets		0
Gain on insurance proceeds		0
Taxes other than income	4.8	4.8
Operating income (loss)	12.2	15.2
Total assets	2,453.0	1,950.3
Gathering and Processing [Member]
Segment Reporting Information [Line Items]
Operating revenues	317.9	304.5
Cost of goods sold	246.4	217.9
Gross margin on revenues	71.5	86.6
Other operation and maintenance	34.3	30.1
Depreciation and amortization	21.8	17.8
Impairment of assets		0.2
Gain on insurance proceeds		(7.5)
Taxes other than income	3.2	2.5
Operating income (loss)	12.2	43.5
Total assets	1,948.9	1,574.1
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0
Cost of goods sold	0	0
Gross margin on revenues	0	0
Other operation and maintenance	(2.3)	(5.3)
Depreciation and amortization	3.0	3.5
Impairment of assets		0
Gain on insurance proceeds		0
Taxes other than income	1.9	1.8
Operating income (loss)	(2.6)	0
Total assets	387.2	257.7
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(88.4)	(60.0)
Cost of goods sold	(89.1)	(59.9)
Gross margin on revenues	0.7	(0.1)
Other operation and maintenance	0	0.1
Depreciation and amortization	0	0
Impairment of assets		0
Gain on insurance proceeds		0
Taxes other than income	0	0
Operating income (loss)	0.7	(0.2)
Total assets	$ (1,945.7)	$ (1,340.4)

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Fair Value Measurements, Fair Value Hierarchy (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 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		$ 0
Collateral Already Posted, Aggregate Fair Value	0.1		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		0
Commodity Contracts Liabilities	0		0
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Contract Assets	0
Commodity Contracts Liabilities	0
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gas Imbalance Asset Fair Value Disclosure	4.2	[1],[2]	3.1	[1],[2]
Gas Imbalance Liability Fair Value Disclosure	4.8	[1],[3]	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	4.2	[1],[2]	3.1	[1],[2]
Gas Imbalance Liability Fair Value Disclosure	4.8	[1],[3]	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	4.2	[1],[2]	3.1	[1],[2]
Gas Imbalance Liability Fair Value Disclosure	4.8	[1],[3]	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]	0	[1],[2]
Gas Imbalance Liability Fair Value Disclosure	0	[1],[3]	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	0.4		0.5
Commodity Contracts Liabilities	0.4		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	0.5		5.5
Commodity Contracts Liabilities	0.6		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		0.5
Commodity Contracts Liabilities	0.6		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	(0.1)		(5.0)
Commodity Contracts Liabilities	(0.2)		(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	8.5		5.9
Fuel Reserves For Over Retained Fuel Due To Shippers	$ 1.1		$ 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 $8.5 million and $5.9 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

[3] Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.1 million and $1.2 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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Common Equity (Tables)

3 Months Ended

Mar. 31, 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
	March 31,
(In millions)	2013		2012
Net Income Attributable to OGE Energy	$	23.1	$	37.1
Average Common Shares Outstanding
Basic average common shares outstanding	98.9		98.3
Effect of dilutive securities:
Contingently issuable shares (performance units)	0.5		0.5
Diluted average common shares outstanding	99.4		98.8
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.23	$	0.38
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.23	$	0.38
Anti-dilutive shares excluded from earnings per share calculation	—		—

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 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)
0.23% - 0.28%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.22% - 0.29%	Muskogee Industrial Authority, January 1, 2025	32.4
0.18% - 0.20%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)		$	135.4

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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	47.5	0	0	37.1	0	10.4	0
Other comprehensive income (loss), net of tax	(2.4)	0	0	0	(1.5)	(0.9)	0
Dividends declared on common stock	(38.7)	0	0	(38.7)	0	0	0
Issuance of common stock	3.7	0	3.7	0	0	0	0
Stock-based compensation and other	(13.4)	0	(16.7)	0	0	(2.6)	5.9
Distributions to noncontrolling interest partners	(5.6)	0	0	0	0	(5.6)	0
Balance at Mar. 31, 2012	2,810.4	1.0	1,021.3	1,573.2	(42.1)	257.3	(0.3)
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	28.0	0	0	23.1	0	4.9	0
Other comprehensive income (loss), net of tax	0.9	0	0	0	0.8	0.1	0
Dividends declared on common stock	(41.4)	0	0	(41.4)	0	0	0
Issuance of common stock	3.2	0	3.2	0	0	0	0
Stock-based compensation and other	(8.3)	0	(10.9)	0	0	(0.9)	3.5
Distributions to noncontrolling interest partners	(2.5)	0	0	0	0	(2.5)	0
Balance at Mar. 31, 2013	$ 3,052.3	$ 1.0	$ 1,038.7	$ 1,754.1	$ (48.3)	$ 306.8	$ 0

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Short-Term Debt and Credit Facilities (Tables)

3 Months Ended

Mar. 31, 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 and available cash at March 31, 2013.

Revolving Credit Agreements and Available Cash
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	663.9	0.38	%	(E)	December 13, 2016
OG&E (C)	400.0		45.2		0.33	%	(E)	December 13, 2016
Enogex LLC (D)	400.0		—		—	%	(E)	See (D) below
	1,550.0		709.1		0.38	%
Cash	7.1		N/A		N/A			N/A
Total	$	1,557.1	$	709.1	0.38	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 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 March 31, 2013, there was $663.9 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 March 31, 2013, there was $43.1 million in outstanding commercial paper borrowings and $2.1 million in letters of credit.

(D) This bank facility was available to provide revolving credit borrowings for Enogex LLC. Effective May 1, 2013, the Midstream Partnershipentered 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.

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

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Gas Gathering Divestiture (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Business Acquisition [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	$ 35.0
Gain (Loss) on Sale of Property Plant Equipment	$ 9.9

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Long-Term Debt (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 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	0.23%
Series Maximum	0.28%
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Series Minimum	0.22%
Series Maximum	0.29%
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Series Minimum	0.18%
Series Maximum	0.20%
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

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
OPERATING REVENUES
Electric Utility operating revenues	$ 455.5	$ 426.7
Natural Gas Midstream Operations operating revenues	445.9	414.0
Total operating revenues	901.4	840.7
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	199.4	183.6
Natural Gas Midstream Operations cost of goods sold	353.6	301.7
Total cost of goods sold	553.0	485.3
Gross margin on revenues	348.4	355.4
OPERATING EXPENSES
Other operation and maintenance	148.0	147.6
Depreciation and amortization	91.9	86.6
Impairment of assets	0	0.2
Gain on insurance proceeds	0	(7.5)
Taxes other than income	33.1	30.2
Total operating expenses	273.0	257.1
OPERATING INCOME	75.4	98.3
OTHER INCOME (EXPENSE)
Interest income	0.1	0
Allowance for equity funds used during construction	1.2	1.9
Other income	14.6	7.7
Other expense	(6.5)	(1.9)
Net other income	9.4	7.7
INTEREST EXPENSE
Interest on long-term debt	39.7	39.2
Allowance for borrowed funds used during construction	(0.7)	(1.1)
Interest on short-term debt and other interest charges	2.2	2.0
Interest expense	41.2	40.1
INCOME BEFORE TAXES	43.6	65.9
INCOME TAX EXPENSE	15.6	18.4
NET INCOME	28.0	47.5
Less: Net income attributable to noncontrolling interests	4.9	10.4
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$ 23.1	$ 37.1
BASIC AVERAGE COMMON SHARES OUTSTANDING (in shares)	98.9	98.3
DILUTED AVERAGE COMMON SHARES OUTSTANDING (in shares)	99.4	98.8
BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS (in dollars per share)	$ 0.23	$ 0.38
DILUTED EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS (in dollars per share)	$ 0.23	$ 0.38
DIVIDENDS DECLARED PER COMMON SHARE (in dollars per share)	$ 0.4175	$ 0.3925

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Fair Value Measurements Carrying and Fair Value Amounts (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 1,904.3	$ 1,904.2
Long-Term Debt, Fair Value	2,368.3	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	10.3	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	105.6	106.3
Enogex LLC Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	448.5	448.4
Long-Term Debt, Fair Value	492.1	493.4
Enogex LLC Term Loan [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	250.0	250.0
Long-Term Debt, Fair Value	250.0	250.0
Carrying (Reported) Amount, Fair Value Disclosure [Member] | Commodity Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Energy Derivative Contract Assets	0.4	0.5
Energy Derivative Contracts Liabilities	0.4	0.3
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Contract [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Energy Derivative Contract Assets	0.4	0.5
Energy Derivative Contracts Liabilities	$ 0.4	$ 0.3

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
CURRENT ASSETS
Cash and cash equivalents	$ 7.1	$ 1.8
Accounts receivable, less reserve of $1.7 and $2.6, respectively	286.9	295.3
Accrued unbilled revenues	49.6	57.4
Income taxes receivable	7.2	7.2
Fuel inventories	99.7	93.3
Materials and supplies, at average cost	82.2	80.9
Price risk management	0.4	0.5
Gas imbalances	12.7	9.0
Deferred income taxes	40.6	187.7
Fuel clause under recoveries	0.4	0
Assets held for sale	0	25.5
Other	39.7	35.6
Total current assets	626.5	794.2
OTHER PROPERTY AND INVESTMENTS, at cost	55.9	52.2
PROPERTY, PLANT AND EQUIPMENT
In service	11,656.8	11,504.4
Construction work in progress	543.6	387.5
Total property, plant and equipment	12,200.4	11,891.9
Less accumulated depreciation	3,620.0	3,547.1
Net property, plant and equipment	8,580.4	8,344.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	502.6	510.6
Intangible assets, net	126.0	127.4
Goodwill	39.4	39.4
Other	51.0	53.6
Total deferred charges and other assets	719.0	731.0
TOTAL ASSETS	9,981.8	9,922.2
CURRENT LIABILITIES
Short-term debt	707.0	430.9
Accounts payable	409.5	396.7
Dividends payable	41.4	41.2
Customer deposits	71.3	70.3
Accrued taxes	28.8	48.1
Accrued interest	35.7	55.0
Accrued compensation	37.1	55.2
Price risk management	0.4	0.3
Gas imbalances	5.7	5.0
Fuel clause over recoveries	81.6	109.2
Other	63.7	64.5
Total current liabilities	1,482.2	1,276.4
LONG-TERM DEBT	2,848.7	2,848.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	399.9	399.8
Deferred income taxes	1,817.7	1,948.8
Deferred investment tax credits	3.4	3.9
Regulatory liabilities	245.5	245.1
Deferred revenues	38.5	37.7
Other	93.6	89.5
Total deferred credits and other liabilities	2,598.6	2,724.8
Total liabilities	6,929.5	6,849.8
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,039.7	1,047.4
Retained earnings	1,754.1	1,772.4
Accumulated other comprehensive loss, net of tax	(48.3)	(49.1)
Treasury stock, at cost	0	(3.5)
Total OGE Energy stockholders' equity	2,745.5	2,767.2
Noncontrolling interests	306.8	305.2
Total stockholders' equity	3,052.3	3,072.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 9,981.8	$ 9,922.2

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Summary of Significant Accounting Policies, Equity Ownership (Details)			8 Months Ended
	Mar. 31, 2013 Atoka [Member]	Mar. 31, 2013 OGE Holdings [Member]	Dec. 31, 2013 OGE Energy [Member]	Dec. 31, 2013 CenterPoint [Member]	Dec. 31, 2013 ArcLight group [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%	79.90%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest			28.50%	58.30%	13.20%

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except as set forth below and in Note 15, the circumstances set forth in Notes 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 additional requests for proposal in mid-2013, along with monthly and daily purchases, all of which are expected to be made at market prices.

Environmental Laws and Regulations

OG&E Notice of Violation

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. OG&E cannot predict at this time when or if litigation will be filed against it as a result of the notice of violation and, if litigation is filed, OG&E cannot predict the outcome of such litigation, but at this time has no reason to believe that it has not acted in compliance with the Federal Clean Air Act. 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 entered an agreement with the Sierra Club to toll the statute of limitations with respect to claims the Sierra Club may assert. The EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment and 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.

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 15 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.

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Summary of Significant Accounting Policies, Regulated Operations (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013		Dec. 31, 2012
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries	$ 0.4		$ 0
Regulatory Assets, Current	30.8		27.0
Regulatory Assets, Non-Current	502.6		510.6
Fuel clause over recoveries	81.6		109.2
Regulatory Liability, Current	109.7		141.1
Regulatory Liability, Non-Current	245.5		245.1
Smart Grid rider over recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	21.6	[1]	24.1	[1]
Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	6.5	[1]	7.8	[1]
Accrued removal obligations, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Non-Current	219.4		218.2
Deferred pension credits [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Non-Current	14.9		17.7
Pension tracker [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Non-Current	11.2		9.2
Crossroads wind farm rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	13.4	[2]	14.9	[2]
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	9.4	[2]	9.2	[2]
Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	7.6	[2]	2.9	[2]
Regulatory Assets, Non-Current	12.3		12.3
Benefit obligations regulatory asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	364.1		370.6
Income taxes recoverable from customers, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	54.9		54.7
Smart Grid [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	42.9		42.8
Unamortized loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	12.7		13.0
Deferred storm expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	12.3		12.7
Deferred pension expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Non-Current	$ 3.4		$ 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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Summary of Significant Accounting Policies (Policies)

3 Months Ended

8 Months Ended

Mar. 31, 2013

Dec. 31, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Equity Method Investments, Policy [Policy Text Block]

Based on the 50/50 management ownership, with neither company having control, effective May 1, 2013, OGE Energy deconsolidated its interest in Enogex LLC and will account for its interest in the Midstream Partnership under the equity method of accounting.

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 three business segments:  (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing.  All significant intercompany transactions have been eliminated in consolidation.

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.

Enogex is a provider of integrated natural gas midstream services.Enogex is engaged in the business of gathering, processing, transporting and storing natural gas.  Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle.Enogex's operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.AtMarch 31, 2013, OGE Energy indirectly owns a79.9 percentmembership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company.  At March 31, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements as OGE Energy had a controlling financial interest over the operations of Enogex Holdings.  Also, at March 31, 2013, Enogex LLC held a 50 percent ownership interest in Atoka.  At March 31, 2013, the Company consolidated Atoka in its Condensed Consolidated Financial Statements as Enogex acted as the managing member of Atoka and had control over the operations of Atoka.

Basis of Accounting [Text Block]

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company atMarch 31, 2013andDecember 31, 2012and the results of its operations and cash flows for the threemonths endedMarch 31, 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 threemonths endedMarch 31, 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.

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 accessibleat 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 thereporting entity'sown 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 carrying value of the financial instruments included in the Condensed Consolidated Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount.The valuation of the Company's energy derivative contracts was determined generally based on quoted market prices.  However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values.  The valuation of instruments also considers the credit risk of the counterparties.The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 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]

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the CondensedConsolidatedBalance Sheets and earnings are recognized in the period in which physical delivery of the commodity occurs.Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by Enogex's operations, (ii) commodity contracts for the purchase and sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

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

Derivatives Not Designated as Hedging Instruments

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

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

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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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Allowance for Doubtful Accounts Receivable	$ 1.7	$ 2.6

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net income	$ 28.0	$ 47.5
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4 and $0.4, respectively	0.9	0.8
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.3 and $0.3, respectively	0.5	0.5
Amortization of prior service cost, net of tax of ($0.3) and ($0.3), respectively	(0.5)	(0.5)
Deferred commodity contracts hedging gains reclassified in net income, net of tax of ($0.1) and ($1.7), respectively	(0.1)	(3.3)
Amortization of deferred interest rate swap hedging losses, net of tax of $0.1 and $0.1, respectively	0.1	0.1
Other comprehensive income (loss), net of tax	0.9	(2.4)
Comprehensive income (loss)	28.9	45.1
Less: Comprehensive income attributable to noncontrolling interests	5.0	9.5
Total comprehensive income attributable to OGE Energy	$ 23.9	$ 35.6

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Common Equity

3 Months Ended

Mar. 31, 2013

Equity [Abstract]

Common Equity

Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 53,601 shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the threemonths endedMarch 31, 2013 and received proceeds of $3.2 million.  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 March 31, 2013, there were 2,068,893 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
	March 31,
(In millions)	2013		2012
Net Income Attributable to OGE Energy	$	23.1	$	37.1
Average Common Shares Outstanding
Basic average common shares outstanding	98.9		98.3
Effect of dilutive securities:
Contingently issuable shares (performance units)	0.5		0.5
Diluted average common shares outstanding	99.4		98.8
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.23	$	0.38
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	0.23	$	0.38
Anti-dilutive shares excluded from earnings per share calculation	—		—

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Document and Entity Information Document	3 Months Ended
	Mar. 31, 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	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding	99,116,609

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Long-Term Debt

3 Months Ended

Mar. 31, 2013

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

AtMarch 31, 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)
0.23% - 0.28%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.22% - 0.29%	Muskogee Industrial Authority, January 1, 2025	32.4
0.18% - 0.20%	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.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.4	$ 0.4
Postretirement Benefit Plans:
Amortization of deferred net loss	0.3	0.3
Amortization of prior service cost	(0.3)	(0.3)
Deferred commodity contracts hedging gains reclassified in net income	(0.1)	(1.7)
Amortization of deferred interest rate swap hedging losses	$ 0.1	$ 0.1

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Noncontrolling Interests

3 Months Ended

Mar. 31, 2013

Noncontrolling Interest [Abstract]

Noncontrolling Interests

Noncontrolling Interests

There were no contributions by OGE Holdings or the ArcLight group to Enogex Holdings during the threemonths endedMarch 31, 2013.

Pursuant to the Enogex Holdings LLC Agreement, Enogex Holdings makes quarterly distributions to its partners. The following table summarizes the quarterly distributions during the threemonths endedMarch 31, 2013.

(In millions)	OGE Holdings' Portion		ArcLight group's Portion		Total Distribution
First quarter 2013	$	10.0	$	2.5	$	12.5

During the threemonths endedMarch 31, 2013, Atoka's noncontrolling interest partner made no contributions to Atoka. Enogex LLC made no distributions during the threemonths endedMarch 31, 2013 to its Atoka partner, as there is no minimum distribution requirement related to Atoka.

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OGE Energy Midstream Partnership with CenterPoint Energy, Inc.

3 Months Ended

Mar. 31, 2013

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

Equity Method Investments and Joint Ventures Disclosure [Text Block]

OGE Energy Midstream Partnership with CenterPoint Energy, Inc.

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 the Midstream Partnership to own and operate the midstream businesses of OGE Energy and CenterPoint that 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 the Midstream Partnership. CenterPoint Energy Field Services, LLC, a Delaware limited liability company and wholly owned subsidiary of CenterPoint, was converted into a Delaware limited partnership that became the Midstream Partnership. CenterPoint contributed to the Midstream Partnership its equity interests in each of CenterPoint Energy Gas Transmission Company, LLC, a Delaware limited liability company, CenterPoint Energy - Mississippi River Transmission, LLC, a Delaware limited liability company, and certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute49 percentof its interest in Southeast Supply Header, LLC, a Delaware limited liability company. CenterPoint Energy Field Services, LLC provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States that interconnect with CenterPoint Energy Gas Transmission Company, LLC and CenterPoint Energy - Mississippi River Transmission, LLC pipelines, as well as other interstate and intrastate pipelines. As of December 31, 2012, CenterPoint Energy Field Services, LLC gathered an average of approximately 2.5 billion cubic feet per day of natural gas. In addition, CenterPoint Energy Field Services, LLC has the capacity available to treat up to 2.5 billion cubic feet per day and process nearly 625 million cubic feet per day of natural gas. CenterPoint Energy Gas Transmission Company, LLC is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas and includes the 1.9 billion cubic feet per day pipeline from Carthage, Texas to Perryville, Louisiana, which CenterPoint Energy Gas Transmission Company, LLC operates as a separate line with a fixed fuel rate. CenterPoint Energy - Mississippi River Transmission, LLC is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Illinois and Missouri. CenterPoint indirectly owns 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. A wholly owned indirect subsidiary of Spectra Energy Corp. owns the remaining 50 percent interest in Southeast Supply Header, LLC. Upon closing, CenterPoint indirectly contributed 49 percent of its interest in the Southeast Supply Header, LLC to the Midstream Partnership. Upon receipt of certain consents, CenterPoint will contribute the remainder of its interest to the Midstream Partnership.

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 May 1, 2013, OGE Energy holds28.5 percentof the limited partners interests, CenterPoint holds58.3 percentof the limited partner interests and the ArcLight group holds13.2 percentof the limited partner interests in the Midstream Partnership, provided, however, if CenterPoint obtains the approvals required to contribute its remaining indirect interest in Southeast Supply Header, LLC within 90 days after closing, CenterPoint will instead hold 59 percent of the limited partner interests, OGE would hold 28 percent of the limited partners interest and the ArcLight group would hold 13 percent of the limited partners interest.

After the expiration of the 90-day period after closing, CenterPoint has certain put rights, and the Midstream Partnership has certain call rights, exercisable with respect to any interest in Southeast Supply Header, LLC retained by CenterPoint following the formation of the Midstream Partnership, under which CenterPoint would contribute to the Midstream Partnership 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 the Midstream Partnership were to exercise such call right, CenterPoint's retained interest in Southeast Supply Header, LLC would be contributed to the Midstream Partnership 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 the Midstream Partnership or from the Midstream Partnership 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 the Midstream Partnership 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 the Midstream Partnership following an initial public offering of the Midstream Partnership. In addition, for a period of time, the ArcLight group will have board observation rights and approval rights over certain material activities of the Midstream Partnership, 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 the Midstream Partnership 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 Energy deconsolidated its interest in Enogex LLC and will account for its interest in the Midstream Partnership under 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 the Midstream Partnership in an initial public offering. OGE Energy can give no assurances that the initial public offering will be consummated. Prior to consummating the initial public offering, OGE Energy, CenterPoint Energy, Inc. and the Midstream Partnership will need to complete the negotiation of the financial and other terms, including the initial public offering price. In addition, consummation of the initial public offering is subject to market conditions. For so long as the ArcLight group maintains a minimum ownership percentage, the ArcLight group is entitled to consult with the Midstream Partnership in connection with the initial public offering. The Midstream Partnership 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.

In connection with the formation of the Midstream Partnership, on May 1, 2013, the Midstream Partnership entered into a $1.05 billion three-year senior unsecured term loan facility, the proceeds of which were used to repay $1.05 billion of intercompany indebtedness owed to CenterPoint. CenterPoint has guaranteed collection of the Midstream Partnership's obligations under the term loan, which guarantee is subordinated to all senior debt of CenterPoint. Effective May 1, 2013, the Midstream Partnership also 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.

At March 31, 2013, Enogex LLC was obligated on approximately $700 million, in the aggregate, in indebtedness under its term loan, its revolving credit agreement and two series of its senior notes maturing in years 2014 and 2020. Certain of the entities contributed to the Midstream Partnership by CenterPoint are obligated on approximately $363 million of indebtedness owed to a wholly owned subsidiary of CenterPoint that is scheduled to mature in 2017.

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 the Midstream Partnership. 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 the Midstream Partnership or (ii) at least 20 percent of the limited partner interests of the Midstream Partnership. "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 the Midstream Partnership), the acquiring party will be required to offer the Midstream Partnership 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 the Midstream Partnership if the acquiring party intends to cease using them in Midstream Operations within 12 months. If the Midstream Partnership 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 board observation rights, the ArcLight group will be prohibited from pursuing any transaction independently from the Midstream Partnership (i) if the ArcLight group's consent is required for the Midstream Partnership to pursue such transaction and (ii) the ArcLight group affirmatively votes not to consent to such transaction.

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Rate Matters and Regulation

3 Months Ended

Mar. 31, 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 Matter

OG&E 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.

Pending Regulatory Matters

OG&E 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 December 19, 2012, witnesses for the OCC Staff filed responsive testimony recommending that the OCC approve OG&E's fuel adjustment clause costs and recoveries for the calendar year 2011 and recommending that the OCC find that OG&E's electric generation, purchased power, fuel procurement and other fuel related practices, policies and decisions during calendar year 2011 were fair, just and reasonable and prudent.  The Oklahoma Industrial Energy Consumers filed a statement of position on December 19, 2012 and did not challenge OG&E's application of its fuel adjustment clause or prudency.  The Oklahoma Industrial Energy Consumers reserved its right to file rebuttal testimony, cross examine witnesses and amend its statement of position should circumstances change or additional information becomes available in the course of this proceeding. On January 7, 2013, the Oklahoma Attorney General filed a statement of position stating that after reviewing the case information the Attorney General has no reason at this time to dispute the findings of the OCC Staff.  On April 9, 2013, a hearing was held in this matter, at which time 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. OG&E expects to receive an order from the OCC by the end of the second quarter of 2013.

Enogex 2013 Fuel Filing

On March 1, 2013, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2013 through March 31, 2014). The deadline for interventions and protests on the filing was March 18, 2013 and no protests were filed. A FERC order is pending.

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Short-Term Debt and Credit Facilities

3 Months Ended

Mar. 31, 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$707.0 millionand$430.9 millionatMarch 31, 2013andDecember 31, 2012, respectively. The following table provides information regarding the Company's revolving credit agreements and available cash at March 31, 2013.

Revolving Credit Agreements and Available Cash
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	663.9	0.38	%	(E)	December 13, 2016
OG&E (C)	400.0		45.2		0.33	%	(E)	December 13, 2016
Enogex LLC (D)	400.0		—		—	%	(E)	See (D) below
	1,550.0		709.1		0.38	%
Cash	7.1		N/A		N/A			N/A
Total	$	1,557.1	$	709.1	0.38	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 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 March 31, 2013, there was $663.9 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 March 31, 2013, there was $43.1 million in outstanding commercial paper borrowings and $2.1 million in letters of credit.

(D) This bank facility was available to provide revolving credit borrowings for Enogex LLC. Effective May 1, 2013, the Midstream Partnershipentered 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.

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

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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Stock-Based Compensation

3 Months Ended

Mar. 31, 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 thethreemonths endedMarch 31, 2013 and 2012related to the Company's performance units and restricted stock.

	Three Months Ended
	March 31,
(In millions)	2013		2012
Performance units
Total shareholder return	$	2.0	$	1.8
Earnings per share	0.6		0.7
Total performance units	2.6		2.5
Restricted stock	0.1		0.2
Total compensation expense	$	2.7	$	2.7
Income tax benefit	$	1.0	$	1.1

The Company has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During thethreemonths endedMarch 31, 2013, there were62,632 of treasury stock shares and 258,260shares 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 thethreemonths endedMarch 31, 2013, there were332sharesof restricted stock returned to the Company to satisfy tax liabilities. The Company received $0.2 million during the threemonths endedMarch 31, 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 threemonths endedMarch 31, 2013 due to the Company being in a tax net operating loss position in 2013.

The following table summarizes the activity of the Company's stock-based compensation during thethreemonths endedMarch 31, 2013.

	Units/Shares	Fair Value
Grants
Performance units (Total shareholder return)	156,974	$	58.61
Performance units (Earnings per share)	37,094	$	53.45
Restricted stock	2,970	$	59.41
Conversions
Performance units (Total shareholder return) (A)	188,631	N/A
Performance units (Earnings per share) (A)	62,880	N/A

(A) Performance units were converted based on a payout ratio of200 percentof the target number of performance units granted in February2010and are included in the258,260 and 62,632shares of common stock issued during thethreemonths endedMarch 31, 2013as discussed above.

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Fair Value Measurements

3 Months Ended

Mar. 31, 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 accessibleat 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 thereporting entity'sown 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 following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at March 31, 2013 and December 31, 2012 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at March 31, 2013 and 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 $0.1 million and $0.2 million of collateral at March 31, 2013 and December 31, 2012, respectively, which has been included within netting adjustments in the table below. The Company held no collateral at March 31, 2013 or December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012. The Company held no Level 1 investments at March 31, 2013 and no Level 3 investments at March 31, 2013 or December 31, 2012.

March 31, 2013
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Significant other observable inputs (Level 2)	$	0.5		$	0.6		$	4.2	$	4.8
Total fair value	0.5			0.6			4.2		4.8
Netting adjustments	(0.1		)	(0.2		)	—		—
Total	$	0.4		$	0.4		$	4.2	$	4.8
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 $8.5 million and $5.9 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(C) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.1 million and $1.2 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the fair value and carrying amount of the Company's financial instruments, including derivative contracts related to the Company's PRM activities, atMarch 31, 2013 and December 31, 2012.

	March 31, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
PRM Assets
Energy Derivative Contracts	$	0.4	$	0.4	$	0.5	$	0.5
PRM Liabilities
Energy Derivative Contracts	$	0.4	$	0.4	$	0.3	$	0.3
Long-Term Debt
OG&E Senior Notes	$	1,904.3	$	2,368.3	$	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		10.3		10.7		10.0
OGE Energy Senior Notes	99.9		105.6		99.9		106.3
Enogex LLC Senior Notes	448.5		492.1		448.4		493.4
Enogex LLC Term Loan	250.0		250.0		250.0		250.0

The carrying value of the financial instruments included in the Condensed Consolidated Balance Sheets approximates fair value except for long-term debt which is valued at the carrying amount.The valuation of the Company's energy derivative contracts was determined generally based on quoted market prices.  However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values.  The valuation of instruments also considers the credit risk of the counterparties.The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.

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Derivative Instruments and Hedging Activities

3 Months Ended

Mar. 31, 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 risks managed using derivatives instruments are commodity price risk and interest rate risk. The Company is also exposed to credit risk in its business operations.

Commodity Price Risk

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

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

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

• natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage Enogex's natural gas exposure associated with its storage and transportation contracts and asset management activities.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the CondensedConsolidatedBalance Sheets and earnings are recognized in the period in which physical delivery of the commodity occurs.Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by Enogex's operations, (ii) commodity contracts for the purchase and sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

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

Interest Rate Risk

The Company's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper.  The Company manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates.  The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes.  Interest rate derivatives are used solelyto 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 designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing operations and natural gas transportation and storage operations (operational gas hedges).  The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex had no instruments designated as cash flow hedges at March 31, 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.

AtMarch 31, 2013andDecember 31, 2012, the Company hadnoderivative instruments that were designated as fair value hedges.

Derivatives Not Designated as Hedging Instruments

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

Quantitative Disclosures Related to Derivative Instruments

At March 31, 2013, the Company had the following derivative instruments that were not designated as hedging instruments.

(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	7.0	71.3
Fixed Swaps/Futures	0.1	0.1
Basis Swaps	5.2	11.6

(A) Natural gas in MMBtu's.  

(B) 94.2 percent of the natural gas contracts have durations of one year or less, 4.2 percenthave durations of more than one year and less than two years and 1.6 percenthave durations of more than two years.

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

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

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet atMarch 31, 2013are as follows:

		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	0.1	$	0.2
Physical Purchases/Sales	Current PRM	0.4		0.4
Total		$	0.5	$	0.6
Total Gross Derivatives (A)		$	0.5	$	0.6

(A) See Note 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet atMarch 31, 2013.

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet atDecember 31, 2012are 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 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet atDecember 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 the three months endedMarch 31, 2013.

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		$	—
Interest Rate Swap	—		(0.2		)	—
Total	$	—	$	—		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.3	)
Total	$	(0.3	)

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months endedMarch 31, 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	$	0.3	$	5.2		$	—
Interest Rate Swap	—		(0.2		)	—
Total	$	0.3	$	5.0		$	—

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(2.4	)
Natural Gas Financial Futures/Swaps	0.4
Total	$	(2.0	)

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 threemonths endedMarch 31, 2013 and 2012, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the threemonths endedMarch 31, 2013 and 2012, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, the Company would have been required to postnocash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position atMarch 31, 2013.  The Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.

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Income Taxes

3 Months Ended

Mar. 31, 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 farms.  In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

On January 2, 2013, the American Taxpayer Relief Act of 2012 was signed into law. Among other things, the law included an extension of bonus depreciation for one year for property generally placed in service before January 1, 2014. Because this new law was enacted in 2013, GAAP requires the law to be considered retroactive legislation, the impact of which must be recorded in the period enacted. The impact of the new law was recorded during the first quarter of 2013 in the Condensed Consolidated Financial Statements as an increase in Deferred Tax Liabilities with a corresponding increase in Deferred Tax Assets related to the net operating loss. With additional bonus depreciation in 2013, the amount of net operating loss classified as a Current Deferred Tax Asset is decreased. Accordingly, a portion of the Current Deferred Tax Asset was reclassified to non-current.

As previously reported in the Company's 2012 Form 10-K, in January 2013, OG&E learned 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.

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Report of Business Segments (Tables)

3 Months Ended

Mar. 31, 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 endedMarch 31, 2013 and 2012.

Three Months Ended March 31, 2013	Electric Utility		Natural Gas Transportation and Storage		Natural Gas Gathering and Processing		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	455.5	$	216.4	$	317.9	$	—		$	(88.4	)	$	901.4
Cost of goods sold	213.0		182.7		246.4		—			(89.1		)	553.0
Gross margin on revenues	242.5		33.7		71.5		—			0.7			348.4
Other operation and maintenance	105.1		10.9		34.3		(2.3		)	—			148.0
Depreciation and amortization	61.3		5.8		21.8		3.0			—			91.9
Taxes other than income	23.2		4.8		3.2		1.9			—			33.1
Operating income (loss)	$	52.9	$	12.2	$	12.2	$	(2.6	)	$	0.7		$	75.4
Total assets	$	7,138.4	$	2,453.0	$	1,948.9	$	387.2		$	(1,945.7	)	$	9,981.8

Three Months Ended March 31, 2012	Electric Utility		Natural Gas Transportation and Storage		Natural Gas Gathering and Processing			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	426.7	$	169.5	$	304.5		$	—		$	(60.0	)	$	840.7
Cost of goods sold	195.5		131.8		217.9			—			(59.9		)	485.3
Gross margin on revenues	231.2		37.7		86.6			—			(0.1		)	355.4
Other operation and maintenance	110.6		12.1		30.1			(5.3		)	0.1			147.6
Depreciation and amortization	59.7		5.6		17.8			3.5			—			86.6
Impairment of assets	—		—		0.2			—			—			0.2
Gain on insurance proceeds	—		—		(7.5		)	—			—			(7.5		)
Taxes other than income	21.1		4.8		2.5			1.8			—			30.2
Operating income (loss)	$	39.8	$	15.2	$	43.5		$	—		$	(0.2	)	$	98.3
Total assets	$	6,632.8	$	1,950.3	$	1,574.1		$	257.7		$	(1,340.4	)	$	9,074.5

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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan	$ 3.2	$ 3.7
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, Dividend Reinvestment Plan and Stock Purchase Plan	53,601
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan	$ 3.2
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan	2,068,893

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Report of Business Segments

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Report of Business Segments

Report of Business Segments

Previously, the Company's business was divided into four segmentsas follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. During the third quarter of 2012,the operations and activities of EER were fully integrated with those of Enogex through the creation of a new commodity management organization.The operations of EER, including asset management activities, have been included in the natural gas transportation and storage segment and have been restated for all prior periods presented. As a result of this change, the Company's business is now divided into three segments for financial reporting purposes as follows: (i) electric utility, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing. 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 endedMarch 31, 2013 and 2012.

Three Months Ended March 31, 2013	Electric Utility		Natural Gas Transportation and Storage		Natural Gas Gathering and Processing		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	455.5	$	216.4	$	317.9	$	—		$	(88.4	)	$	901.4
Cost of goods sold	213.0		182.7		246.4		—			(89.1		)	553.0
Gross margin on revenues	242.5		33.7		71.5		—			0.7			348.4
Other operation and maintenance	105.1		10.9		34.3		(2.3		)	—			148.0
Depreciation and amortization	61.3		5.8		21.8		3.0			—			91.9
Taxes other than income	23.2		4.8		3.2		1.9			—			33.1
Operating income (loss)	$	52.9	$	12.2	$	12.2	$	(2.6	)	$	0.7		$	75.4
Total assets	$	7,138.4	$	2,453.0	$	1,948.9	$	387.2		$	(1,945.7	)	$	9,981.8

Three Months Ended March 31, 2012	Electric Utility		Natural Gas Transportation and Storage		Natural Gas Gathering and Processing			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	426.7	$	169.5	$	304.5		$	—		$	(60.0	)	$	840.7
Cost of goods sold	195.5		131.8		217.9			—			(59.9		)	485.3
Gross margin on revenues	231.2		37.7		86.6			—			(0.1		)	355.4
Other operation and maintenance	110.6		12.1		30.1			(5.3		)	0.1			147.6
Depreciation and amortization	59.7		5.6		17.8			3.5			—			86.6
Impairment of assets	—		—		0.2			—			—			0.2
Gain on insurance proceeds	—		—		(7.5		)	—			—			(7.5		)
Taxes other than income	21.1		4.8		2.5			1.8			—			30.2
Operating income (loss)	$	39.8	$	15.2	$	43.5		$	—		$	(0.2	)	$	98.3
Total assets	$	6,632.8	$	1,950.3	$	1,574.1		$	257.7		$	(1,340.4	)	$	9,074.5

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Noncontrolling Interests (Tables)

3 Months Ended

Mar. 31, 2013

Noncontrolling Interest [Abstract]

Schedule of Distributions Made to Members or Limited Partners, by Distribution [Table Text Block]

The following table summarizes the quarterly distributions during the threemonths endedMarch 31, 2013.

(In millions)	OGE Holdings' Portion		ArcLight group's Portion		Total Distribution
First quarter 2013	$	10.0	$	2.5	$	12.5

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Stock-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit	$ 1.0		$ 1.1
Stock-Based Compensation Activity
Cash Received from Exercise of Stock Options	0.2
Tax Benefit Realized from Exercise of Stock Options	0
Maximum payout range	200.00%
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	2.6		2.5
Restricted Stock [Member]
Stock-Based Compensation Activity
Number of shares granted	2,970
Fair value of shares granted	$ 59.41
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	2.7		2.7
Common Stock
Stock-Based Compensation Activity
Number of shares issued	258,260
Restricted Stock [Member]
Stock-Based Compensation Activity
Shares Paid for Tax Withholding for Share Based Compensation	332
Treasury Stock [Member]
Stock-Based Compensation Activity
Number of shares issued	62,632
Total Shareholder Return [Member]
Stock-Based Compensation Activity
Number of shares granted	156,974
Fair value of shares granted	$ 58.61
Equity Instruments Other than Options, Converted in Period	188,631	[1]
Total Shareholder Return [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	2.0		1.8
Performance Units Related to Earnings Per Share [Member]
Stock-Based Compensation Activity
Number of shares granted	37,094
Fair value of shares granted	$ 53.45
Equity Instruments Other than Options, Converted in Period	62,880	[1]
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	0.6		0.7
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 0.1		$ 0.2

[1] Performance units were converted based on a payout ratio of 200 percent of the target number of performance units granted in February 2010 and are included in the 258,260 and 62,632 shares of common stock issued during the three months ended March 31, 2013 as discussed above.

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OGE Energy Midstream Partnership with CenterPoint Energy, Inc. (Details) (USD $) In Millions, unless otherwise specified	8 Months Ended
	Dec. 31, 2013	May 01, 2013	Mar. 31, 2013
Percentage of Subsidiary Owned by Another Company		50.00%
Line of Credit Facility, Maximum Borrowing Capacity			$ 1,550.0
Value of Midstream Operations Assets or Equity Acquired		50.0
Value of Aggregate Midstream Operations Assets or Equity Acquired by Parties Not Offered in Midstream Partnership		100.0
Enogex Llc [Member]
Percentage of Enogex LLC Contributed		100.00%
Line of Credit Facility, Maximum Borrowing Capacity			400.0	[1]
Long-term debt			700.0
OGE Holdings [Member]
Contributions to Pay Down Short-Term Debt		9.1
OGE Energy [Member]
Percentage of Limited Partner Interests Held in Midstream Partnership	28.50%
Percent of Limited Partner Interests Held if Approvals Are Obtained	28.00%
Percentage Share of Management Rights		50.00%
General Partner's Share of Undistributed Earnings, Incentive Distribution Right Embedded in General Partner Interest		60.00%
CenterPoint [Member]
Percentage of Limited Partner Interests Held in Midstream Partnership	58.30%
Percent of Limited Partner Interests Held if Approvals Are Obtained	59.00%
Percentage Share of Management Rights		50.00%
General Partner's Share of Undistributed Earnings, Incentive Distribution Right Embedded in General Partner Interest		40.00%
Long-term debt			363.0
ArcLight group [Member]
Contributions to Pay Down Short-Term Debt		107.0
Percentage of Limited Partner Interests Held in Midstream Partnership	13.20%
Percent of Limited Partner Interests Held if Approvals Are Obtained	13.00%
Southeast Supply Header, LLC [Member]
Percentage of Subsidiary Contributed		49.00%
Midstream Partnership [Member]
Term Loan Facility		1,050.0
Outstanding Intercompany Borrowings		1,050.0
Line of Credit Facility, Maximum Borrowing Capacity		1,400.0

[1] This bank facility was available to provide revolving credit borrowings for Enogex LLC. Effective May 1, 2013, the Midstream Partnership 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.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 28.0	$ 47.5
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	92.9	87.6
Impairment of assets	0	0.2
Deferred income taxes and investment tax credits, net	15.4	18.4
Allowance for equity funds used during construction	(1.2)	(1.9)
(Gain) loss on disposition and abandonment of assets	(8.7)	0.5
Gain on insurance proceeds	0	(7.5)
Stock-based compensation	(8.3)	(11.8)
Price risk management assets	0.1	(0.5)
Price risk management liabilities	0.1	(4.9)
Regulatory assets	5.5	5.6
Regulatory liabilities	(4.1)	(3.4)
Other assets	(0.1)	1.4
Other liabilities	6.3	5.2
Change in certain current assets and liabilities
Accounts receivable, net	8.4	54.8
Accrued unbilled revenues	7.8	6.0
Fuel, materials and supplies inventories	(7.7)	3.3
Gas imbalance assets	(3.7)	(4.0)
Fuel clause under recoveries	(0.4)	1.8
Other current assets	(4.1)	(6.3)
Accounts payable	16.5	(59.2)
Gas imbalance liabilities	0.7	(1.5)
Fuel clause over recoveries	(27.6)	31.5
Other current liabilities	(56.6)	(42.5)
Net Cash Provided from Operating Activities	59.2	120.3
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(325.1)	(311.1)
Proceeds from insurance	0	6.1
Reimbursement of capital expenditures	0	9.7
Proceeds from sale of assets	35.6	0.2
Net Cash Used in Investing Activities	(289.5)	(295.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term debt	276.1	212.2
Issuance of common stock	3.2	3.7
Distributions to noncontrolling interest partners	(2.5)	(5.6)
Dividends paid on common stock	(41.2)	(38.5)
Net Cash Provided from Financing Activities	235.6	171.8
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5.3	(3.0)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1.8	4.6
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 7.1	$ 1.6

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Gas Gathering Divestiture

3 Months Ended

Mar. 31, 2013

Gas Gathering Divestiture [Abstract]

Gas Gathering Divestiture [Text Block]

Gas Gathering Divestiture

Texas Panhandle Gathering Divestiture

As previously reported in the Company's 2012 Form 10-K, on January 2, 2013, Enogex and one of its five largest customers entered into new agreements, effective January 1, 2013, relating to the customer's gathering and processing volumes on the Texas portion of Enogex's system. The effects of this new arrangement are (i) a fixed-fee processing agreement replaced the previous keep-whole agreement, (ii) the acreage dedicated by the customer to Enogex for gathering and processing in Texas was increased for an extended term and (iii) the sale by Enogex of certain gas gathering assets in the Texas Panhandle portion of Enogex's system to this customer for cash proceeds of approximately$35 million. Enogex recognized a pre-tax gain of$9.9 millionin the first quarter of 2013 in its natural gas gathering and processing segment from the sale of these assets which is included in Other Income in the Condensed Consolidated Statements of Income.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

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

The following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at March 31, 2013 and December 31, 2012 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at March 31, 2013 and 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 $0.1 million and $0.2 million of collateral at March 31, 2013 and December 31, 2012, respectively, which has been included within netting adjustments in the table below. The Company held no collateral at March 31, 2013 or December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012. The Company held no Level 1 investments at March 31, 2013 and no Level 3 investments at March 31, 2013 or December 31, 2012.

March 31, 2013
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Significant other observable inputs (Level 2)	$	0.5		$	0.6		$	4.2	$	4.8
Total fair value	0.5			0.6			4.2		4.8
Netting adjustments	(0.1		)	(0.2		)	—		—
Total	$	0.4		$	0.4		$	4.2	$	4.8
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 $8.5 million and $5.9 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(C) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.1 million and $1.2 million at March 31, 2013 and December 31, 2012, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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

The following table summarizes the fair value and carrying amount of the Company's financial instruments, including derivative contracts related to the Company's PRM activities, atMarch 31, 2013 and December 31, 2012.

	March 31, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
PRM Assets
Energy Derivative Contracts	$	0.4	$	0.4	$	0.5	$	0.5
PRM Liabilities
Energy Derivative Contracts	$	0.4	$	0.4	$	0.3	$	0.3
Long-Term Debt
OG&E Senior Notes	$	1,904.3	$	2,368.3	$	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		10.3		10.7		10.0
OGE Energy Senior Notes	99.9		105.6		99.9		106.3
Enogex LLC Senior Notes	448.5		492.1		448.4		493.4
Enogex LLC Term Loan	250.0		250.0		250.0		250.0

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			3 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Atoka Noncontrolling Interest [Member]	Dec. 31, 2012 Atoka Noncontrolling Interest [Member]	Mar. 31, 2013 Commodity Contract [Member]	Mar. 31, 2013 Interest Rate Swap [Member]	Mar. 31, 2013 Noncontrolling Interest [Member]	Mar. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member] Defined Benefit Plan Income Loss [Member]	Mar. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member] Defined Benefit Plan Prior Service Cost [Member]	Mar. 31, 2013 Pension Plans, Defined Benefit [Member] Defined Benefit Plan Income Loss [Member]	Mar. 31, 2013 Pension Plans, Defined Benefit [Member] Defined Benefit Plan Prior Service Cost [Member]
Components of Accumulated Other Comprehensive Income [Roll Forward]
Balance at December 31, 2012							$ (15.7)	$ 7.2	$ (49.3)	$ 0.1
Amounts reclassified from accumulated other comprehensive income (loss)							0.5	(0.5)	0.9	0
Balance at March 31, 2013							(15.2)	6.7	(48.4)	0.1
Components of Accumulated Other Comprehensive Income Hedging [Roll Forward]
Balance at December 31, 2012				0.1	(0.5)
Amounts reclassified from accumulated other comprehensive income (loss)				(0.1)	0.1
Balance at March 31, 2013				0	(0.4)
Components of Accumulated Other Comprehensive Income Noncontrolling Interest [Roll Forward]
Balance at December 31, 2012	(49.1)	0	0			(9.0)
Amounts reclassified from accumulated other comprehensive income (loss)	0.8					0.1
Balance at March 31, 2013	$ (48.3)	$ 0	$ 0			$ (8.9)

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Retirement Plans and Postretirement Benefit Plans

3 Months Ended

Mar. 31, 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						Three Months Ended
	March 31,						March 31,
(In millions)	2013 (B)			2012 (B)			2013 (B)		2012 (B)
Service cost	$	5.0		$	4.5		$	0.3	$	0.3
Interest cost	6.6			7.5			0.1		0.1
Expected return on plan assets	(12.3		)	(11.5		)	—		—
Amortization of net loss	6.2			5.9			0.1		0.1
Amortization of unrecognized prior service cost (A)	0.5			0.6			0.1		0.2
Net periodic benefit cost	$	6.0		$	7.0		$	0.6	$	0.7

(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$6.6 millionand$7.7 millionof net periodic benefit cost recognizedduring thethreemonths endedMarch 31, 2013and2012, respectively, OG&E recognized an increase in pension expense during thethreemonths endedMarch 31, 2013and2012of$1.9 millionand$2.9 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
	March 31,
(In millions)	2013 (B)			2012 (B)
Service cost	$	1.2		$	1.0
Interest cost	2.6			3.0
Expected return on plan assets	(0.6		)	(0.8		)
Amortization of transition obligation	—			0.7
Amortization of net loss	5.3			5.1
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)
Net periodic benefit cost	$	4.4		$	4.9

(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$4.4 millionand$4.9 millionof net periodic benefit cost recognizedduring thethreemonths endedMarch 31, 2013and2012, respectively, OG&E recognized an increase in postretirement medical expense duringthethreemonths endedMarch 31, 2013and2012of$0.1 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).

The capitalized portion of net periodic pension benefit cost was $1.1 million during the threemonths endedMarch 31, 2013 as compared to $1.5 million during the same period in 2012. The capitalized portion of net periodic postretirement benefit cost was $0.8 million during the threemonths endedMarch 31, 2013 as compared to $1.0 million during the same period in 2012.