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 endedSeptember 30, 2015

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 September 30, 2015, there were 199,702,572 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDEDSEPTEMBER 30, 2015

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	26
Item 3. Quantitative and Qualitative Disclosures About Market Risk	43
Item 4. Controls and Procedures	43
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	44
Item 6. Exhibits	44
Signature	45

i

GLOSSARY OF TERMS

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

Abbreviation	Definition
2014 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2014
ALJ	Administrative Law Judge
APSC	Arkansas Public Service Commission
ArcLight	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ASU	Financial Accounting Standards Board Accounting Standards Update
AVEC	Arkansas Valley Electric Cooperative Corporation
BART	Best available retrofit technology
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2	Carbon dioxide
Company	OGE Energy, collectively with its subsidiaries
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
Enable	Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC	Enogex LLC, collectively with its subsidiaries (effective July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIP	Federal implementation plan
GAAP	Accounting principles generally accepted in the United States
IRP	Integrated Resource Plans
MATS	Mercury and Air Toxics Standards
Mustang Modernization Plan	OG&E's plan to replace the soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
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, parent company of Enogex Holdings (prior to May 1, 2013) and 26.3 percent owner of Enable Midstream Partners
Pension Plan	Qualified defined benefit retirement plan
Ppb	Parts per billion
PSO	Public Service Company of Oklahoma
PUD	Public Utility Division of the Oklahoma Corporation Commission
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SESH	Southeast Supply Header, LLC
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 2014Form 10-K and"Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factorsthat could cause actual results to differ materiallyfrom the forward-looking statementsinclude, but are not limited to:

• general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;

• the ability ofthe Company and its subsidiariesto access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

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

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

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

• business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;

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

• unusual weather;

• availability and prices of raw materials for current and future construction projects;

• Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition entersthe Company'smarkets;

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

• changes in accounting standards, rules or guidelines;

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

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

• advances in technology;

• creditworthiness of suppliers, customers and other contractual parties;

• difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment inEnable that the Company does not control;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's2014 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 September 30,						Nine Months Ended September 30,
(In millions except per share data)	2015			2014			2015			2014
OPERATING REVENUES	$	719.8		$	754.7		$	1,749.8		$	1,926.9
COST OF SALES	259.8			305.3			682.3			869.6
OPERATING EXPENSES
Other operation and maintenance	109.4			108.1			334.3			331.9
Depreciation and amortization	77.9			71.7			230.0			207.2
Taxes other than income	21.9			21.5			68.8			66.5
Total operating expenses	209.2			201.3			633.1			605.6
OPERATING INCOME	250.8			248.1			434.4			451.7
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	(71.9		)	44.7			(12.0		)	131.9
Allowance for equity funds used during construction	2.2			1.1			5.4			3.0
Other income	8.9			7.2			19.4			11.7
Other expense	(5.3		)	(5.8		)	(8.5		)	(11.2		)
Net other income (expense)	(66.1		)	47.2			4.3			135.4
INTEREST EXPENSE
Interest on long-term debt	37.0			36.3			110.9			109.2
Allowance for borrowed funds used during construction	(1.1		)	(0.6		)	(2.7		)	(1.7		)
Interest on short-term debt and other interest charges	1.1			1.5			4.2			5.0
Interest expense	37.0			37.2			112.4			112.5
INCOME BEFORE TAXES	147.7			258.1			326.3			474.6
INCOME TAX EXPENSE	36.5			70.8			84.4			137.2
NET INCOME	$	111.2		$	187.3		$	241.9		$	337.4
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7			199.3			199.6			199.1
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.7			200.2			199.6			199.9
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.55		$	0.94		$	1.21		$	1.69
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.55		$	0.94		$	1.21		$	1.69
DIVIDENDS DECLARED PER COMMON SHARE	$	0.27500		$	0.25000		$	0.77500		$	0.70000

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 September 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014
Net income	$	111.2		$	187.3		$	241.9		$	337.4
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.3, $0.3, $1.7 and $0.9, respectively	0.7			0.5			1.9			1.4
Settlement cost, net of tax of $2.4, $0.0, $2.4 and $0.0, respectively	3.8			—			3.8			—
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.2, $0.1, $0.6 and $0.4, respectively	0.3			0.1			0.9			0.6
Amortization of prior service cost, net of tax of ($0.3), ($0.2), ($0.8) and ($0.8), respectively	(0.4		)	(0.4		)	(1.3		)	(1.3		)
Amortization of deferred interest rate swap hedging losses, net of tax of $0.0, $0.0, $0.0 and $0.1, respectively	—			0.1			—			0.2
Other comprehensive income, net of tax	4.4			0.3			5.3			0.9
Comprehensive income	$	115.6		$	187.6		$	247.2		$	338.3

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

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	241.9		$	337.4
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	230.0			207.2
Deferred income taxes and investment tax credits, net	62.3			142.1
Equity in earnings of unconsolidated affiliates	12.0			(131.9		)
Distributions from unconsolidated affiliates	67.1			110.1
Allowance for equity funds used during construction	(5.4		)	(3.0		)
Stock-based compensation	3.8			(5.4		)
Excess tax benefit on stock-based compensation	(5.2		)	—
Regulatory assets	12.7			1.6
Regulatory liabilities	(13.9		)	(5.6		)
Other assets	12.7			(18.8		)
Other liabilities	0.1			24.8
Change in certain current assets and liabilities
Accounts receivable, net	(33.8		)	(58.8		)
Accounts receivable - unconsolidated affiliates	0.5			5.5
Accrued unbilled revenues	(22.4		)	(13.3		)
Fuel, materials and supplies inventories	(25.5		)	33.5
Fuel clause under recoveries	66.7			(58.1		)
Other current assets	(8.9		)	(6.4		)
Accounts payable	(57.7		)	(100.7		)
Fuel clause over recoveries	34.5			(0.4		)
Other current liabilities	37.6			6.7
Net Cash Provided from Operating Activities	609.1			466.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(375.0		)	(437.4		)
Return of capital - equity method investments	36.9			9.5
Proceeds from sale of assets	2.2			0.6
Net Cash Used in Investing Activities	(335.9		)	(427.3		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(149.7		)	(134.3		)
Proceeds from long-term debt	—			246.5
Issuance of common stock	7.2			10.1
Excess tax benefit on stock-based compensation	5.2			—
Payment of long-term debt	(0.1		)	(140.1		)
Decrease in short-term debt	(98.0		)	(28.2		)
Net Cash Used in Financing Activities	(235.4		)	(46.0		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	37.8			(6.8		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5.5			6.8
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	43.3		$	—

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

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2015		December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	43.3	$	5.5
Accounts receivable, less reserve of $1.5 and $1.6, respectively	222.6		188.8
Accounts receivable - unconsolidated affiliates	5.1		5.6
Accrued unbilled revenues	77.9		55.5
Income taxes receivable	18.4		16.0
Fuel inventories	86.2		58.5
Materials and supplies, at average cost	76.7		78.9
Deferred income taxes	176.4		191.4
Fuel clause under recoveries	1.6		68.3
Other	44.9		38.4
Total current assets	753.1		706.9
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,202.2		1,318.2
Other	70.5		70.1
Total other property and investments	1,272.7		1,388.3
PROPERTY, PLANT AND EQUIPMENT
In service	10,198.7		9,983.0
Construction work in progress	230.6		115.9
Total property, plant and equipment	10,429.3		10,098.9
Less accumulated depreciation	3,262.8		3,119.0
Net property, plant and equipment	7,166.5		6,979.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	389.7		410.4
Other	35.8		42.3
Total deferred charges and other assets	425.5		452.7
TOTAL ASSETS	$	9,617.8	$	9,527.8

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

5

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

(In millions)	September 30, 2015			December 31, 2014
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	—		$	98.0
Accounts payable	125.7			179.1
Dividends payable	54.9			49.9
Customer deposits	76.0			73.7
Accrued taxes	61.4			39.7
Accrued interest	34.1			43.0
Accrued compensation	37.1			38.2
Long-term debt due within one year	110.0			—
Fuel clause over recoveries	34.5			—
Other	53.1			51.7
Total current liabilities	586.8			573.3
LONG-TERM DEBT	2,645.5			2,755.3
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	311.0			315.5
Deferred income taxes	2,333.5			2,268.3
Regulatory liabilities	277.0			263.0
Other	110.6			108.0
Total deferred credits and other liabilities	3,032.1			2,954.8
Total liabilities	6,264.4			6,283.4
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,104.2			1,087.6
Retained earnings	2,285.3			2,198.2
Accumulated other comprehensive loss, net of tax	(36.1		)	(41.4		)
Total stockholders' equity	3,353.4			3,244.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,617.8		$	9,527.8

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)			Total
Balance at December 31, 2014	$	2.0	$	1,085.6		$	2,198.2		$	(41.4	)	$	3,244.4
Net income	—		—			241.9			—			241.9
Other comprehensive income, net of tax	—		—			—			5.3			5.3
Dividends declared on common stock	—		—			(154.8		)	—			(154.8		)
Issuance of common stock	—		7.2			—			—			7.2
Stock-based compensation	—		9.4			—			—			9.4
Balance at September 30, 2015	$	2.0	$	1,102.2		$	2,285.3		$	(36.1	)	$	3,353.4
Balance at December 31, 2013	$	2.0	$	1,071.6		$	1,991.7		$	(28.2	)	$	3,037.1
Net income	—		—			337.4			—			337.4
Other comprehensive income, net of tax	—		—			—			0.9			0.9
Dividends declared on common stock	—		—			(139.5		)	—			(139.5		)
Issuance of common stock	—		10.1			—			—			10.1
Stock-based compensation	—		(3.0		)	—			—			(3.0		)
Balance at September 30, 2014	$	2.0	$	1,078.7		$	2,189.6		$	(27.3	)	$	3,243.0

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

7

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments:  (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and has the ability to exercise significant influence.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operationsare conducted through OG&E andare subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company.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.

The natural gas midstream operations segment currently represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

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

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 atSeptember 30, 2015andDecember 31, 2014, the results of its operations for the three and nine months endedSeptember 30, 2015and2014 and the results of its cash flows for thenine months endedSeptember 30, 2015and2014, 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 thethree and nine months endedSeptember 30, 2015are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2015or 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 2014Form 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.

Certain prior-year amounts have been reclassified to conform with the current year presentation.

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 refunded in future rates.

The following table is a summary of OG&E's regulatory assets and liabilities at:

(In millions)	September 30, 2015		December 31, 2014
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	30.3	$	19.7
Fuel clause under recoveries	1.6		68.3
Other (A)(C)	9.8		10.2
Total Current Regulatory Assets	$	41.7	$	98.2
Non-Current
Benefit obligations regulatory asset	$	241.6	$	261.1
Income taxes recoverable from customers, net	55.7		56.1
Smart Grid	43.7		43.9
Deferred storm expenses	16.6		17.5
Unamortized loss on reacquired debt	15.1		16.1
Other (C)	17.0		15.7
Total Non-Current Regulatory Assets	$	389.7	$	410.4
Regulatory Liabilities
Current
Crossroads wind farm rider over recovery (B)	$	7.2	$	10.3
Smart Grid rider over recovery (B)	5.3		12.5
Fuel clause over recoveries	34.5		—
Other (B)	2.2		1.6
Total Current Regulatory Liabilities	$	49.2	$	24.4
Non-Current
Accrued removal obligations, net	$	257.1	$	248.1
Pension tracker	19.9		14.9
Total Non-Current Regulatory Liabilities	$	277.0	$	263.0

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

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

(C) Prior year amount of$1.1 millionreclassified from Non-Current Other assets to Current Other assets.

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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Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. As discussed above, OGE Energy accounts for the investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. OGE Energy's maximum exposure to loss related to Enable is limited to OGE Energy's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at September 30, 2015. The Company evaluates its equity method investment for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment, and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment which are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during thenine months endedSeptember 30, 2015and2014.

	Nine Months Ended September 30,
(In millions)	2015			2014
Balance at January 1	$	58.6		$	55.2
Liabilities settled (A)	(0.4		)	(0.2		)
Accretion expense	1.9			1.9
Revisions in estimated cash flows (B)	1.6			1.7
Balance at September 30	$	61.7		$	58.6

(A) In 2015, asset retirement obligations were settled for the asbestos abatement at one of OG&E's generating facilities.

(B) Assumptions changed related to the estimated cost of removal for one of OG&E's generating facilities.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the nine months endedSeptember 30, 2015. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan							Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Settlement cost		Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1	$	—	$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9			—		3.8		0.9			(1.3		)	5.3
Net current period other comprehensive income (loss)	1.9			—		3.8		0.9			(1.3		)	5.3
Balance at September 30, 2015	$	(34.9	)	$	0.1	$	3.8	$	(7.1	)	$	2.0		$	(36.1	)

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The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and nine months endedSeptember 30, 2015 and 2014.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015			2014			2015			2014
Losses on cash flow hedges
Interest rate swap	$	—		$	(0.1	)	$	—		$	(0.3	)	Interest expense
	—			(0.1		)	—			(0.3		)	Total before tax
	—			—			—			(0.1		)	Tax benefit
	$	—		$	(0.1	)	$	—		$	(0.2	)	Net of tax
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.0	)	$	(0.8	)	$	(3.6	)	$	(2.3	)	(A)
Settlement cost	(6.2		)	—			(6.2		)	—			(A)
	(7.2		)	(0.8		)	(9.8		)	(2.3		)	Total before tax
	(2.7		)	(0.3		)	(4.1		)	(0.9		)	Tax benefit
	$	(4.5	)	$	(0.5	)	$	(5.7	)	$	(1.4	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	(0.5	)	$	(0.2	)	$	(1.5	)	$	(1.0	)	(A)
Prior service credit	0.7			0.6			2.1			2.1			(A)
	0.2			0.4			0.6			1.1			Total before tax
	0.1			0.1			0.2			0.4			Tax (benefit) expense
	$	0.1		$	0.3		$	0.4		$	0.7		Net of tax
Total reclassifications for the period	$	(4.4	)	$	(0.3	)	$	(5.3	)	$	(0.9	)	Net of tax

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

2. Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. For public entities, the deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017.

In April 2015, the FASB issued ASU 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". The amendments in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments. The FASB issued the updated guidance as part of its initiative to reduce complexity in accounting standards, as it had received feedback that having different balance sheet presentation requirements for debt issuance costs and debt discount and premium created unnecessary complexity. On June 18, 2015, the SEC observer stated that given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to revolving debt arrangements, the SEC staff would not object to an entity deferring and presenting

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such costs as an asset and subsequently amortizing them ratably over the term of the revolving debt arrangement. For public business entities, the amendments in this ASU are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company will reflect the impact of this ASU in the first quarter of 2016.

3. Investment in Unconsolidated Affiliate and Related Party Transactions

On March 14, 2013, OGE Energy entered into a Master Formation Agreement with the ArcLight group and CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight Group and CenterPoint Energy, Inc., agreed to form Enable to own and operate the midstream businesses of OGE Energy and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight group indirectly contributed100 percentof the equity interests inEnogex LLCto Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost.

On April 16, 2014, Enable completed an initial public offering of 25,000,000 common units resulting in Enable becoming a publicly traded Master Limited Partnership. In connection with Enable’s initial public offering, approximately 61.4 percent of OGE Holdings and CenterPoint’s common units were converted into subordinated units. As a result, following the initial public offering, OGE Holdings owned 42,832,291 common units and 68,150,514 subordinated units of Enable. Holders of subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordinated units will convert into common units when Enable has paid at least the minimum quarterly distribution for three years or paid at least 150 percent of the minimum quarterly distribution for one year.

On July 22, 2015, Enable announced a quarterly dividend distribution of $0.31600per unit on its outstanding common and subordinated units, representing an increase of approximately 1.1 percent over the prior quarter distribution. Enable's gross margins are affected by commodity price movements. Based on forward commodity prices, Enable expects to see a decrease in producer activity that will affect its future distribution growth rate. If cash distributions to Enable’s unitholders exceed $0.330625per unit in any quarter, the general partner will receive increasing percentages, up to50 percent, of the cash Enable distributes in excess of that amount. OGE Holdings is entitled to60 percentof those “incentive distributions.” In certain circumstances, the general partner will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

On October 22, 2015, Enable announced a quarterly dividend distribution of$0.31800per unit on its outstanding common and subordinated units, representing an increase of approximately 0.6 percent over the prior quarter distribution. Distributions received from Enable were $35.1 million and $33.6 million for the three months endedSeptember 30, 2015 and 2014, respectively, and $104.0 million and $110.1 million for the nine months endedSeptember 30, 2015 and 2014, respectively.

At September 30, 2015, OGE Energy held 26.3 percent of the limited partner interests in Enable.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below. Prior to May 1, 2013, operating costs charged and related party transactions between the Company and Enogex Holdings were eliminated in consolidation. OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013.

On May 1, 2013, OGE Energy and Enable entered into a Services Agreement, Employee Transition Agreement, and other agreements whereby OGE Energy agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. The support services automatically extend year-to-year at the end of the initial term, unless terminated by Enable with at least 90 days’ notice. Enable may terminate the initial support services at any time with 180 days' notice if approved by the board of Enable's general partner. Under these agreements, OGE Energy charged operating costs to Enable of $2.6 million and $3.3 million (which results in a corresponding reduction to OGE Energy's operations and maintenance expense) for the three months endedSeptember 30, 2015 and 2014, respectively, and $7.9 million and $13.1 million for the nine months endedSeptember 30, 2015 and 2014, respectively. OGE Energy charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as such.  Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

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Additionally, OGE Energy agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, CenterPoint, OGE Energy and Enable agreed to continue the secondment to Enable of 192 OGE Energy employees that participate in OGE Energy's defined benefit and retirement plans beyond December 31, 2014. OGE Energy billed Enable for reimbursement of $7.0 million and $25.0 million during the three months endedSeptember 30, 2015 and September 30, 2014, respectively, and $25.1 million and $78.0 million during the nine months endedSeptember 30, 2015 and September 30, 2014, respectively, under the Transitional Seconding Agreement for employment costs.

OGE Energy had accounts receivable from Enable of $5.1 million and $5.6 million as of September 30, 2015 and December 31, 2014, respectively, for amounts billed for transitional services, including the cost of seconded employees.

Related Party Transactions with Enable

OG&E entered into a new contract with Enable to provide transportation services effective May 1, 2014 which eliminated the natural gas storage services. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries.The following table summarizes related party transactions between OG&E and its affiliate, Enable, during thethree and nine months endedSeptember 30, 2015 and 2014.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2015		2014		2015		2014
Operating Revenues:
Electricity to power electric compression assets	$	4.4	$	4.1	$	11.1	$	10.1
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.8	$	26.3	$	26.2
Natural gas storage services	—		0.1		—		4.5
Natural gas purchases	2.5		3.4		7.1		6.9

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2015 and December 31, 2014 and for the three and nine months endedSeptember 30, 2015 and 2014.

Balance Sheet	September 30, 2015		December 31, 2014
	(In millions)
Current assets	$	427	$	438
Non-current assets	10,774		11,399
Current liabilities	804		671
Non-current liabilities	2,786		2,344

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Income Statement	2015			2014		2015			2014
	(In millions)
Operating revenues	$	646		$	803	$	1,852		$	2,632
Cost of sales	287			439		856			1,550
Operating income	(975		)	152		(778		)	452
Net income	(985		)	139		(817		)	408

The formation of Enable was considered a business combination, and CenterPoint Midstream was the acquirer of Enogex Holdings for accounting purposes.  Under this method, the fair value of the consideration paid by CenterPoint Midstream for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex

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Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to equity of $2.2 billion. Due to the contribution of Enogex LLC to Enable, meeting the requirements of being in substance real estate and thus recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

OGE Energy recorded a loss in equity in earnings of unconsolidated affiliates of $71.9 million and $12.0 million for the three and nine months endedSeptember 30, 2015 and an increase in equity in earnings of unconsolidated affiliates of $44.7 million and $131.9 million for the three and nine months endedSeptember 30, 2014. Equity in earnings of unconsolidated affiliates includes OGE Energy'sshare of Enable's earnings adjusted for the amortization of the basis difference of OGE Energy's original investment in Enogex and its underlying equity in net assets of Enable. The basis difference is the result of the initial contribution of Enogex to Enable in May 2013, and subsequent issuances of equity by Enable, including the IPO in April 2014 and the issuance of common units for the acquisition of CenterPoint's 24.95 percent interest in SESH. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed.Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above.

The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was$0.8 billion as of September 30, 2015.

The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for thethree and nine months endedSeptember 30, 2015 and 2014.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2015			2014		2015			2014
(In millions)
OGE's share of Enable Net Income (Loss)	$	(80.3	)	$	36.4	$	(35.9	)	$	111.1
Amortization of basis difference	3.5			3.4		10.6			10.4
Elimination of Enogex Holdings fair value and other adjustments	4.9			4.9		13.3			10.4
OGE's Equity in earnings of unconsolidated affiliates	$	(71.9	)	$	44.7	$	(12.0	)	$	131.9

Enable tests its goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. Subsequent to the completion of the October 1, 2014 annual test and previous interim assessment as of December 31, 2014, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which Enable operates. Based on the decline in producer activity and the forecasted impact on future periods, in addition to an increase in the weighted average cost of capital, Enable determined that the impact on its forecasted operating profits and cash flows for its gathering and processing and transportation and storage segments for the next five years would be significantly reduced. As a result, when Enable performed the first step of its annual goodwill impairment analysis as of October 1, 2015, it determined that the carrying value of the gathering and processing and transportation and storage segments exceeded fair value. Enable completed the second step of the goodwill impairment analysis comparing the implied fair value for those reporting units to the carrying amount of that goodwill and determined that goodwill for those units was completely impaired in the amount of $1,086.4 millionas ofSeptember 30, 2015.

Accordingly, theCompany recorded a$108.4 millionpre-tax charge in thethree and nine months endedSeptember 30, 2015for its share of the goodwill impairment, as adjusted for the basis differences.

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4. Fair Value Measurements

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

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

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

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The Company had nofinancial instruments measured at fair value on a recurring basis atSeptember 30, 2015 and December 31, 2014.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2015 and December 31, 2014.

	September 30, 2015				December 31, 2014
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,510.0	$	2,800.5	$	2,509.7	$	2,957.7
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.1		9.3		10.2		10.3
OGE Energy Senior Notes	100.0		99.9		100.0		99.9

The Company's long-term debt is recorded at the carrying amount.The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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5. Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree and nine months endedSeptember 30, 2015 and 2014related to the Company's performance units and restricted stock.

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Performance units
Total shareholder return	$	1.9		$	2.0	$	5.7	$	5.9
Earnings per share	(0.8		)	0.1		0.3		2.2
Total performance units	1.1			2.1		6.0		8.1
Restricted stock	—			—		0.1		0.1
Total compensation expense	1.1			2.1		6.1		8.2
Less: Amount paid by unconsolidated affiliates	(0.2		)	0.6		0.3		2.5
Net compensation expense	$	1.3		$	1.5	$	5.8	$	5.7
Income tax benefit	$	0.5		$	0.6	$	2.3	$	2.2

The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units. During the three and nine months endedSeptember 30, 2015, there were 912 shares and 81,865shares, respectively, of new common stock issued pursuant to the Company's stock incentive plans related to restricted stock grants (net of forfeitures) and payouts of earned performance units. During thethree and nine months endedSeptember 30, 2015, there wereno shares and 1,070 shares, respectively, of restricted stock returned to the Company to satisfy tax liabilities.

6. 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 to2012or state and local tax examinations by tax authorities for years prior to2011.  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 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 and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

As previously reported, OG&E has determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During the third quarter of 2015, OG&E recorded an additional reserve for this item of$3.8 million ($2.4 millionafter the federal tax benefit) related to Oklahoma investment tax credits generated in the current year 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.

7. Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 16,498 shares and 217,370 shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months endedSeptember 30, 2015 and received proceeds of $0.5 million and $7.2 million, respectively.  The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital requirements or working capital needs.  At September 30, 2015, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

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Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions except per share data)	2015		2014		2015		2014
Net Income	$	111.2	$	187.3	$	241.9	$	337.4
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.3		199.6		199.1
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—		0.9		—		0.8
Diluted average common shares outstanding	199.7		200.2		199.6		199.9
Basic Earnings Per Average Common Share	$	0.55	$	0.94	$	1.21	$	1.69
Diluted Earnings Per Average Common Share	$	0.55	$	0.94	$	1.21	$	1.69
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

8. Long-Term Debt

AtSeptember 30, 2015, 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)
0.05%	-	0.13%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.06%	-	0.19%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.14%	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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9. 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$98.0 millionatDecember 31, 2014, with no balance at September 30, 2015. The following table provides information regarding the Company's revolving credit agreements at September 30, 2015.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	—	—	%	(D)	December 13, 2018
OG&E (C)	400.0		1.9		0.95	%	(D)	December 13, 2018
Total	$	1,150.0	$	1.9	0.95	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2015.

(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.  

(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.

(D) 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 by itself 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, 2015 and ending December 31, 2016.

10. Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During the first nine months of 2015, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, the Company recorded pension settlement charges of $16.2 million in the third quarter of 2015. The pension settlement charge did not require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charge was an acceleration of costs that otherwise would be recognized as pension expense in future periods. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in the pension tracker in the regulatory assets and liabilities table in Note 1.

The details of net periodic benefit cost, before consideration of capitalized amounts, 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:

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Net Periodic Benefit Cost

	Pension Plan												Restoration of Retirement Income Plan
	Three Months Ended						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)			2015 (B)		2014 (B)		2015 (C)		2014 (C)
Service cost	$	4.2		$	3.9		$	12.1		$	11.5		$	0.4	$	0.3	$	1.0	$	0.8
Interest cost	6.6			7.0			19.6			21.1			0.2		0.2		0.5		0.5
Expected return on plan assets	(11.0		)	(11.3		)	(34.5		)	(34.0		)	—		—		—		—
Amortization of net loss	3.8			3.6			13.5			10.7			0.2		0.1		0.5		0.2
Amortization of unrecognized prior service cost (A)	0.1			0.4			0.3			1.3			—		—		0.1		0.1
Settlement	16.2			—			16.2			—			—		—		—		—
Total net periodic benefit cost	19.9			3.6			27.2			10.6			0.8		0.6		2.1		1.6
Less: Amount paid by unconsolidated affiliates	1.0			0.9			3.1			2.6			—		—		0.1		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	18.9		$	2.7		$	24.1		$	8.0		$	0.8	$	0.6	$	2.0	$	1.5

(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$19.7 millionand$3.3 millionof net periodic benefit cost recognizedduring thethree months endedSeptember 30, 2015and2014, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedSeptember 30, 2015and2014of$2.7 millionand$2.8 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thethree months endedSeptember 30, 2015 of $7.4 millionrelated tothe pension settlement charge of$16.2 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thethree months endedSeptember 30, 2015 of $1.4 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$16.2 million.

(C) In addition to the$26.1 millionand$9.5 millionof net periodic benefit cost recognizedduring thenine months endedSeptember 30, 2015and2014, respectively, OG&E recognized the following:

• an increase in pension expense during thenine months endedSeptember 30, 2015and2014of$8.0 millionand$8.4 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);

• a deferral of pension expense during thenine months endedSeptember 30, 2015 of $7.4 millionrelated tothe pension settlement charge of$16.2 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thenine months endedSeptember 30, 2015 of $1.4 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$16.2 million.

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	Postretirement Benefit Plans
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)
Service cost	$	0.4		$	0.7		$	1.2		$	2.3
Interest cost	2.6			2.8			7.7			8.5
Expected return on plan assets	(0.6		)	(0.6		)	(1.8		)	(1.8		)
Amortization of net loss	3.5			3.1			10.4			9.3
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)	(12.4		)	(12.4		)
Total net periodic benefit cost	1.8			1.9			5.1			5.9
Less: Amount paid by unconsolidated affiliates	0.4			0.3			1.0			1.0
Net periodic benefit cost (net of unconsolidated affiliates)	$	1.4		$	1.6		$	4.1		$	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$1.4 millionand$1.6 millionof net periodic benefit cost recognizedduring thethree months endedSeptember 30, 2015and2014, respectively, OG&E recognized an increase in postretirement medical expense duringthethree months endedSeptember 30, 2015and2014of$1.4 millionand$1.3 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1).

(C) In addition to the$4.1 millionand$4.9 millionof net periodic benefit cost recognizedduring thenine months endedSeptember 30, 2015and2014, respectively, OG&E recognized an increase in postretirement medical expense duringthenine months endedSeptember 30, 2015and2014of$4.3 millionand$3.9 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).

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2015		2014		2015		2014
Capitalized portion of net periodic pension benefit cost	$	2.6	$	0.9	$	4.6	$	2.6
Capitalized portion of net periodic postretirement benefit cost	0.5		0.5		1.4		1.5

11. Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy, and (ii) the natural gas midstream operations segment. 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.

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The following tables summarize the results of the Company's business segments during the three and nine months endedSeptember 30, 2015 and 2014.

Three Months Ended September 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	719.8	$	—		$	—		$	—		$	719.8
Cost of sales	259.8		—			—			—			259.8
Other operation and maintenance	107.4		4.9			(2.9		)	—			109.4
Depreciation and amortization	75.9		—			2.0			—			77.9
Taxes other than income	21.0		—			0.9			—			21.9
Operating income (loss)	255.7		(4.9		)	—			—			250.8
Equity in earnings of unconsolidated affiliates (A)	—		(71.9		)	—			—			(71.9		)
Other income (expense)	6.6		—			(0.7		)	(0.1		)	5.8
Interest expense	36.4		—			0.7			(0.1		)	37.0
Income tax expense	63.0		(26.8		)	0.3			—			36.5
Net income (loss)	$	162.9	$	(50.0	)	$	(1.7	)	$	—		$	111.2
Investment in unconsolidated affiliates	$	—	$	1,202.2		$	—		$	—		$	1,202.2
Total assets	$	8,570.7	$	1,541.5		$	134.0		$	(628.4	)	$	9,617.8

Three Months Ended September 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	754.7	$	—		$	—		$	—		$	754.7
Cost of sales	305.3		—			—			—			305.3
Other operation and maintenance	111.0		0.3			(3.2		)	—			108.1
Depreciation and amortization	69.4		—			2.3			—			71.7
Taxes other than income	20.6		—			0.9			—			21.5
Operating income (loss)	248.4		(0.3		)	—			—			248.1
Equity in earnings of unconsolidated affiliates (A)	—		44.7			—			—			44.7
Other income (expense)	2.9		—			(0.3		)	(0.1		)	2.5
Interest expense	35.3		—			2.0			(0.1		)	37.2
Income tax expense	58.7		16.2			(4.1		)	—			70.8
Net income (loss)	$	157.3	$	28.2		$	1.8		$	—		$	187.3
Investment in unconsolidated affiliates	$	—	$	1,311.1		$	—		$	—		$	1,311.1
Total assets	$	8,003.1	$	1,427.2		$	204.1		$	(171.7	)	$	9,462.7

(A) The Company recorded a $108.4 million pre-tax charge during the three months endedSeptember 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

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Nine Months Ended September 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,749.8	$	—		$	—		$	—		$	1,749.8
Cost of sales	682.3		—			—			—			682.3
Other operation and maintenance	337.3		5.9			(8.9		)	—			334.3
Depreciation and amortization	224.0		—			6.0			—			230.0
Taxes other than income	65.7		—			3.1			—			68.8
Operating income (loss)	440.5		(5.9		)	(0.2		)	—			434.4
Equity in earnings of unconsolidated affiliates (A)	—		(12.0		)	—			—			(12.0		)
Other income (expense)	13.9		—			2.6			(0.2		)	16.3
Interest expense	110.5		—			2.1			(0.2		)	112.4
Income tax expense	94.9		(8.7		)	(1.8		)	—			84.4
Net income (loss)	$	249.0	$	(9.2	)	$	2.1		$	—		$	241.9
Investment in unconsolidated affiliates	$	—	$	1,202.2		$	—		$	—		$	1,202.2
Total assets	$	8,570.7	$	1,541.5		$	134.0		$	(628.4	)	$	9,617.8

Nine Months Ended September 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,926.9	$	—		$	—		$	—		$	1,926.9
Cost of sales	869.6		—			—			—			869.6
Other operation and maintenance	343.1		0.7			(11.9		)	—			331.9
Depreciation and amortization	198.7		—			8.5			—			207.2
Taxes other than income	63.1		—			3.4			—			66.5
Operating income (loss)	452.4		(0.7		)	—			—			451.7
Equity in earnings of unconsolidated affiliates (A)	—		131.9			—			—			131.9
Other income (expense)	4.5		—			(0.8		)	(0.2		)	3.5
Interest expense	106.7		—			6.0			(0.2		)	112.5
Income tax expense	95.3		49.6			(7.7		)	—			137.2
Net income (loss)	$	254.9	$	81.6		$	0.9		$	—		$	337.4
Investment in unconsolidated affiliates	$	—	$	1,311.1		$	—		$	—		$	1,311.1
Total assets	$	8,003.1	$	1,427.2		$	204.1		$	(171.7	)	$	9,462.7

(A) The Company recorded a $108.4 million pre-tax charge during the nine months endedSeptember 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

12. Commitments and Contingencies

Except as set forth below, in Note13 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes14and15 to the Company's Consolidated Financial Statements included in the Company's 2014Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Other Purchase Obligation and Contingencies

On June 15, 2015 OG&E entered into a contract with Siemens Energy Inc. for the purchase, design and engineering of seven simple-cycle gas turbine generators for$170.3 millionto be completed byJune 1, 2018.

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Environmental Laws and Regulations

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

On July 8, 2013, the U.S. Department of Justice, filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. The Sierra Club intervened in this proceeding. On September 6, 2013, OG&E filed a Motion to Dismiss the case.  On January 15, 2015, U.S. District Judge Timothy DeGuisti dismissed the complaints filed by the EPA and Sierra Club.  The Court held that it lacked subject matter jurisdiction over the Plaintiffs’ claims because Plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution.   The court also ruled in the alternative that, even if the Plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.”  The EPA and the Sierra Club did not file an appeal of the Court’s ruling.

On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008, were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the Eastern District dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the Eastern District to dismiss its remaining claims with prejudice. On August 27, 2014, the Eastern District granted the Sierra Club's request. The Sierra Club has filed a Notice of Appeal with the 10th Circuit where oral argument was held on March 18, 2015.

At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act, and OG&E expects to vigorously defend against the claims that have been asserted. If OG&E does not prevail in the remainder of the proceedings, the Sierra Club could seek to require OG&E to install additional pollution control equipment at Muskogee 6, including scrubbers, baghouses and selective catalytic reduction systemsand pay fines and significant penalties as a result of the allegations. 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. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.

Air Quality Control System

On September 10, 2014,  OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2.  OG&E entered into an agreement on February 9, 2015, to install the scrubber systems.  The scrubbers are part of OG&E’s Environmental Compliance Plan and are scheduled to be completed by 2019. More detail regarding the Environmental Plan can be found under the “Pending Regulatory Matters” in Note 13.

Clean Power Plan

On August 3, 2015, the EPA issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates.  The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan.  The EPA has given states the option to develop compliance plans for annual rate-based reductions (lb/MWh) or mass-based tonnage limits for CO₂.  The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed43 percentreduction to32 percentin the final rule.  The mass-based approach for existing units calls for a24 percentreduction by 2030 in Oklahoma.  The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission.  The compliance period begins in 2022, and emission reductions will be phased in to 2030.  The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan is not submitted to the EPA.  OG&E is currently evaluating the Clean Power Plan rules and is working in collaboration with the State of Oklahoma on OG&E's plans.

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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, 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.

13. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note15to the Company's Consolidated Financial Statements included in the Company's 2014Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Arkansas Regulatory Developments

The State of Arkansas earlier in 2015 enacted two laws related to rate filings. Act 725, among other things, provides a public utility the option, to be exercised concurrently with the filing of a general rate application, to file notice of its intent to exercise its right for an annual formula rate review so as to provide a streamlined review of the utility’s rates to determine if adjustments in rates are justified. If the utility exercises such rights, rates may be adjusted if the earned return rate is 0.5 percent above or below the target return rate. This procedure is expected to reduce regulatory lag in Arkansas. Act 725 additionally allows for evidence to be presented, relative to the calculation of the return on common equity, comparing the requested return on common equity to approved returns on common equity for public utilities delivering similar services with corresponding risks within Arkansas and also in similar regulatory jurisdictions in the same general part of the country.

Act 1000 amends and clarifies existing interim rate requirements to expand the types of expenses that may be recorded and specifically authorize the recovery of allowance for funds used during construction. Act 1000 allows a public utility to file for an interim rate schedule through which it may recover investments and expenses, including allowance for funds used during construction, expended complying with legislative or administrative rules, regulations, or requirements related to the protection of the public, health, safety, or the environment. Rates are implemented at the time of filing of the interim rate schedule, subject to refund. As permitted by Act 1000, on May 8, 2015, OG&E filed an interim rate schedule to recover expenditures for the Arkansas portion of the low NOx burners made in order to comply with the Regional Haze rule for NOx.

Pending Regulatory Matters

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance and Mustang Modernization Plan included in this application to be approximately$1.1 billion. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

As previously reported, on June 8, 2015 the ALJ issued his report on OG&E's application. While the ALJ in his report agrees that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s environmental compliance plan is the best approach, the ALJ makes various recommendations including, among others, that: (i) the OCC should not raise rates at this time; (ii) with respect to OG&E’s environmental compliance plan, the OCC should grant pre-approval of the estimated costs for new equipment as set by contract, including installation costs covered by a contract, but pre-approval of other equipment and installation costs that were still being negotiated at the end of the evidentiary hearing on April 8, 2015 should be deferred and may be considered in the next general rate case; (iii) the foregoing pre-approval is subject to the condition that the OCC should direct OG&E to issue requests for information for at least 200 MWs of wind power

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within thirty days of a final order; (iv) the OCC should postpone consideration of all other cost recovery issues until the next general rate case; (v) the OCC should direct the PUD Director to commence a general rate case; and (vi) the OCC should deny the Mustang Modernization Plan. OG&E filed exceptions to the ALJ's report in which OG&E set forth the various findings and recommendations that OG&E believes to be erroneous, including the ALJ’s refusal to recommend a recovery rider for OG&E environmental compliance plan and the ALJ’s recommendation that the OCC should deny the Mustang Modernization Plan. The OCC heard oral arguments on June 25, 2015 and took the case under advisement. On July 21, 2015, Commissioner Bob Anthony (one of the three commissioners on the OCC) issued his deliberation statement that was consistent with many parts of the ALJ Report, including the ALJ’s support of OG&E’s environmental compliance plan, the ALJ’s recommendation, as described above, to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other costs recovery issues until the next general rate case. OG&E cannot predict the outcome of this proceeding.

Integrated Resource Plans

In August 2015, OG&E initiated the process to update its IRP pursuant to the OCC rules. After engaging interested stakeholders in August and September, OG&E finalized the 2015 IRP and submitted it to the OCC on October 1, 2015. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the environmental compliance plan and other parts of the action plan contained in the IRP submitted in 2014.

Oklahoma Demand Program Rider Review

In July 2012, OG&E filed an application with the OCC to recover certain costs associated with Demand Programs through the Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off peak hours during the months of May through October, by offering lower rates to those customers in the off peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates.  Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers, by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.

In December 2012, the OCC issued an order approving the recovery of costs associated with the Demand Programs, including the lost revenues associated with the SmartHours program, subject to the Oklahoma PUD staff review.

In March 2014, the Oklahoma PUD staff began their review of the Demand Program cost, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the Oklahoma PUD staff on the methodology to be used to calculate lost revenues associated with the SmartHours program and the amount of lost revenue for 2013, which totaled$10.1 million. The agreement also included utilizing the same methodology for calculating lost revenues for 2014, which resulted in lost revenues for 2014 of$11.6 million.

In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues, in accordance with the agreement that it believed had been reached with the Oklahoma PUD staff.

In April 2015, the Oklahoma PUD staff filed an application, seeking an order from the OCC determining the proper calculation methodology for lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues.  In the application, the Oklahoma PUD staff recommends the OCC approve the Oklahoma PUD staff methodology for calculating lost revenues associated with the SmartHours program, which differs from the methodology that OG&E believes it had agreed upon and which would result in recovery of lost revenue for 2013 of only$4.9 million, a reduction of$5.2 millionfrom the amount recorded by OG&E for 2013.

OG&E believes that the methodology agreed to in November 2014, is consistent with the 2012 OCC order, and believes that it is probable that it will recover the$10.1 millionof lost revenues associated with 2013, the$11.6 millionassociated with 2014 and the $11.1 million associated with year-to-date 2015. A hearing was held on June 30, 2015 and July 1, 2015. OG&E is unable to predict when it will receive a ruling from the OCC.

Fuel Adjustment Clause Review for Calendar Year 2013

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. On May 21, 2015, the ALJ recommended that the OCC find that OG&E's 2013 electric generation, purchased power and fuel procurement processes and costs were prudent,

25

accurate and properly applied to customer billing statements. OG&E received an order to that effect from the OCC on June 17, 2015.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 2, 2015. A hearing is scheduled to be held on April 7, 2016.

Oklahoma Rate Case Filing

On July 28, 2015 OG&E filed a notice of intent with the OCC to file a general rate case on or before November 30, 2015 based on a June 30, 2015 test year and to modify rates no later than 180 days from the date of filing the rate case.  Among the matters OG&E expects the rate case to address are certain cost recovery riders, the retail portion of transmission expenditures made by OG&E since the last rate case, ad valorem taxes, depreciation rates, impact of the expiration of OG&E’s wholesale contracts and the costs associated with the SPP Integrated Market.

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

Introduction

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments:  (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and has the ability to exercise significant influence.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operationsare conducted through OG&E andare subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company.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.

The natural gas midstream operations segment currently represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

On July 22, 2015, Enable announced a quarterly dividend distribution of $0.31600per unit on its outstanding common and subordinated units, representing an increase of approximately 1.1 percent over the prior quarter distribution. Enable's gross margins are affected by commodity price movements. Based on forward commodity prices, Enable expects to see a decrease in producer activity that will affect its future distribution growth rate. If cash distributions to Enable’s unitholders exceed $0.330625per unit in any quarter, the general partner will receive increasing percentages, up to50 percent, of the cash Enable distributes in excess of that amount. OGE Holdings is entitled to60 percentof those “incentive distributions.”

On October 22, 2015, Enable announced a quarterly dividend distribution of$0.3180per unit on its outstanding common and subordinated units, representing an increase of approximately 0.6 percent over the prior quarter distribution.

Overview

Company Strategy

The Company'smission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructureand meet individual customers' needs for energy and related services focusing on safety, efficiency, reliability, customer service and risk management. The Company's corporate strategy is to continue

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to maintain its existing business mix and diversified asset position of its regulated electric utility business and interest in a publicly traded midstream company,while providing competitive energy products and services to customers 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 for OG&E of three to five percent on a weather-normalized basis, maintaining a strong credit rating as well as targeting dividend increases of approximately 10 percent annually through 2019. The targeted annual dividend increase 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 and the composition of the Company's assets and investment opportunities. The Company also relies on cash distributions from its investment in Enable to fund its capital needs and support future dividend growth. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and maintaining strong regulatory and legislative relationships.

Summary of Operating Results

Three Months Ended September 30, 2015as Compared toThree Months Ended September 30, 2014

Net income attributable to OGE Energy was$111.2 million, or$0.55per diluted share, during thethree months endedSeptember 30, 2015as compared to$187.3 million, or$0.94per diluted share, during the same period in2014. Thedecreasein net income of$76.1 million, or$0.39 per diluted share, during thethree months endedSeptember 30, 2015as compared to the same period in2014was primarily due to:

• a decrease in net income attributable to OGE Holdings of $78.2 million, or $0.39 per diluted share of the Company's common stock primarily due to a goodwill impairment, lower average natural gas prices and lower NGLs prices, as well as a pension settlement charge; and

• a decreasein net income at OGE Energy of$3.5 million, or $0.03per diluted share of the Company's common stock,reflecting an increase in income tax expense offset by lower interest expense.

Thesedecreases were partially offset byan increasein net income attributable to OG&E of$5.6 million, or $0.03 per diluted share of Company's common stock, primarily due to higher gross margin, lower operation and maintenance expense and higher other income partially offset by higher depreciation and amortization expense, higher taxes other than income and higher interest expense.

Nine Months Ended September 30, 2015as Compared toNine Months Ended September 30, 2014

Net income attributable to OGE Energy was$241.9 million, or$1.21per diluted share, during thenine months endedSeptember 30, 2015as compared to$337.4 million, or$1.69per diluted share, during the same period in2014. Thedecreasein net income of$95.5 million, or$0.48 per diluted share, during thenine months endedSeptember 30, 2015as compared to the same period in2014was primarily due to:

• a decrease in net income attributable to OGE Holdings of $90.8 million, or $0.46 per diluted share of the Company's common stock, primarily due to a goodwill impairment, lower average natural gas prices, lower NGLs prices, as well as a pension settlement charge; and

• a decrease in net income at OG&E of $5.9 million, or $0.03 per diluted share of the Company's common stock, reflecting an increase in depreciation expense due to additional transmission assets being placed into service in 2014 and higher taxes other than income. These decreases were partially offset by an increase in gross margin, a decrease in operation and maintenance expense, higher other income and a decrease in income tax expense.

Thesedecreases were partially offset byan increase in net income attributable to OGE Energy of $1.2 million, or $0.01per diluted share of the Company's common stock, primarily due to gains associated with the deferred compensation plan and a decrease in interest expense offset by an increase in income tax expense.

2015 Outlook

The Company projects 2015 ongoing consolidated earnings guidance, which excludes non-cash charges, to be at the low end of the earnings range of $1.76 to $1.89 per average diluted share. The utility is now projected to be at the low end of the $1.41 and $1.49 per average diluted share range primarily due to mild summer weather as compared to normal and environmental

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compliance assets placed into service that have not been included in rates.  Distributable cash flow from Enable is projected to be approximately $140 million for 2015. See the Company's 2014Form 10-K for other key factors and assumptions underlying its 2015 earnings guidance.

Non-GAAP Financial Measures

Ongoing Earnings and Ongoing Earnings per Average Diluted Share, which exclude non-cash charges of approximately $108.4 million or $0.33 per average diluted share associated with the Company’s share of Enable’s goodwill impairment as well as a non-cash pension settlement charge of approximately $4.8 million or $0.02 per average diluted share, are non-GAAP financial measures. The Company’s management believes that ongoing earnings and ongoing earnings per average diluted share provide a more meaningful comparison of earnings results and are more representative of the Company’s fundamental core earnings power. The Company’s management uses ongoing earnings and ongoing earnings per average diluted share internally for financial planning and analysis, for reporting of results to the Board of Directors, and when communicating its earnings outlook to analysts and investors. Reconciliations of ongoing earnings and ongoing earnings per average diluted share for the three months ended September 30, 2015 and 2014 are below.

Reconciliation of Ongoing Earnings (Loss) to GAAP Earnings (Loss)
(Net of tax, in millions)	2015 GAAP Earnings (Loss)			Goodwill and Pension Settlement Charges (A)		2015 Ongoing Earnings (Loss)			2014 GAAP and Ongoing Earnings (Loss) (B)
OG&E	$	162.9		$	—	$	162.9		$	157.3
Natural Gas Midstream Operations	(50.0		)	69.8		19.8			28.2
Holding Company	(1.7		)	—		(1.7		)	1.8
Consolidated	$	111.2		$	69.8	$	181.0		$	187.3

Reconciliation of Ongoing Earnings (Loss) per Average Diluted Share to GAAP Earnings (Loss) per Average Diluted Share
	2015 GAAP Earnings (Loss) per Share			Goodwill and Pension Settlement Charges per Share (A)		2015 Ongoing Earnings (Loss) per Share			2014 GAAP and Ongoing Earnings (Loss) per Share (B)
OG&E	$	0.82		$	—	$	0.82		$	0.79
Natural Gas Midstream Operations	(0.25		)	0.35		0.10			0.14
Holding Company	(0.02		)	—		(0.02		)	0.01
Consolidated	$	0.55		$	0.35	$	0.90		$	0.94

(A) The Company recognized a non-cash charge of $108.4 million or $0.33 per average diluted share for its portion of Enable's goodwill impairment. Additionally, the Company recognized a non-cash charge of $4.8 million or $0.02 per average diluted share for a pension settlement charge related to Enable.

(B) There were no similar charges for the year ended December 31, 2014, therefore ongoing and GAAP earnings are the same.

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Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for thethree and nine months endedSeptember 30, 2015as compared to the same period in2014and the Company's consolidated financial position atSeptember 30, 2015. Due to seasonal fluctuations and other factors, the Company'soperating results for thethree and nine months endedSeptember 30, 2015are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2015or 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				Nine Months Ended
	September 30,				September 30,
(In millions except per share data)	2015		2014		2015		2014
Net income attributable to OGE Energy	$	111.2	$	187.3	$	241.9	$	337.4
Basic average common shares outstanding	199.7		199.3		199.6		199.1
Diluted average common shares outstanding	199.7		200.2		199.6		199.9
Basic earnings per average common share	$	0.55	$	0.94	$	1.21	$	1.69
Diluted earnings per average common share	$	0.55	$	0.94	$	1.21	$	1.69
Dividends declared per common share	$	0.27500	$	0.25000	$	0.77500	$	0.70000

Results by Business Segment

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2015			2014		2015			2014
Net income (loss) attributable to OGE Energy
OG&E (Electric Utility)	$	162.9		$	157.3	$	249.0		$	254.9
OGE Holdings (Natural Gas Midstream Operations) (A)	(50.0		)	28.2		(9.2		)	81.6
Other Operations (B)	(1.7		)	1.8		2.1			0.9
Consolidated net income attributable to OGE Energy	$	111.2		$	187.3	$	241.9		$	337.4

(A) Subsequent to the completion of the October 1, 2014 annual test and previous interim assessment as of December 31, 2014, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which Enable operates. As a result, when Enable performed the first step of its annual goodwill impairment analysis as of October 1, 2015, it determined that the carrying value of the gathering and processing and transportation and storage segments exceeded fair value. Enable completed the second step of the goodwill impairment analysis comparing the implied fair value for those reporting units to the carrying amount of that goodwill and determined that goodwill for those units was completely impaired in the amount of $1,086.4 millionas ofSeptember 30, 2015. Accordingly, theCompany recorded a$108.4 millionpre-tax charge in thethree and nine months endedSeptember 30, 2015for its share of the goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

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

The following discussion of results of operations 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				Nine Months Ended
	September 30,				September 30,
(Dollars in millions)	2015		2014		2015		2014
Operating revenues	$	719.8	$	754.7	$	1,749.8	$	1,926.9
Cost of sales	259.8		305.3		682.3		869.6
Other operation and maintenance	107.4		111.0		337.3		343.1
Depreciation and amortization	75.9		69.4		224.0		198.7
Taxes other than income	21.0		20.6		65.7		63.1
Operating income	255.7		248.4		440.5		452.4
Allowance for equity funds used during construction	2.2		1.1		5.4		3.0
Other income	4.8		2.4		9.8		3.0
Other expense	0.4		0.6		1.3		1.5
Interest expense	36.4		35.3		110.5		106.7
Income tax expense	63.0		58.7		94.9		95.3
Net income	$	162.9	$	157.3	$	249.0	$	254.9
Operating revenues by classification
Residential	$	318.1	$	300.9	$	726.7	$	738.6
Commercial	176.5		181.1		423.0		454.2
Industrial	59.2		67.7		150.2		174.5
Oilfield	49.1		54.6		128.2		146.4
Public authorities and street light	63.4		68.3		154.1		172.3
Sales for resale	0.9		13.3		21.7		41.3
System sales revenues	667.2		685.9		1,603.9		1,727.3
Off-system sales revenues	13.5		25.8		34.8		78.0
Other	39.1		43.0		111.1		121.6
Total operating revenues	$	719.8	$	754.7	$	1,749.8	$	1,926.9
Reconciliation of gross margin to revenue:
Operating revenues	$	719.8	$	754.7	$	1,749.8	$	1,926.9
Cost of sales	259.8		305.3		682.3		869.6
Gross Margin	$	460.0	$	449.4	$	1,067.5	$	1,057.3
Megawatt-hour sales by classification (In millions)
Residential	3.1		2.8		7.4		7.3
Commercial	2.1		2.0		5.7		5.5
Industrial	1.0		1.1		2.8		2.9
Oilfield	0.8		0.9		2.5		2.6
Public authorities and street light	0.9		0.8		2.4		2.4
Sales for resale	—		0.3		0.5		0.8
System sales	7.9		7.9		21.3		21.5
Off-system sales	0.4		0.7		1.1		1.9
Total sales	8.3		8.6		22.4		23.4
Number of customers	821,596		812,546		821,596		812,546
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	2.668		3.858		2.666		4.718
Coal	2.209		2.159		2.170		2.148
Total fuel	2.300		2.592		2.245		2.818
Total fuel and purchased power	2.973		3.429		2.925		3.546
Degree days (A)
Heating - Actual	—		10		1,984		2,280
Heating - Normal	19		19		2,020		2,020
Cooling - Actual	1,372		1,293		1,993		1,985
Cooling - Normal	1,380		1,380		2,018		2,018

(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

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between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day.  The daily calculations are then totaled for the particular reporting period.

Three Months Ended September 30, 2015as Compared toThree Months Ended September 30, 2014

OG&E's net incomeincreased$5.6 million, or3.6 percent, during thethree months endedSeptember 30, 2015as compared to the same period in2014primarily due to higher gross margin, higher other income and lower other operation and maintenance partially offset by higher depreciation and amortization expense and higher interest expense.

Gross Margin

Gross Margin is defined by OG&E as operating revenues less cost of sales, which is fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies.

Operating revenues were$719.8 millionduring thethree months endedSeptember 30, 2015as compared to$754.7 millionduring the same period in2014, a decreaseof$34.9 million, or4.6 percent. Cost of sales were$259.8 millionduring thethree months endedSeptember 30, 2015as compared to$305.3 millionduring the same period in2014, a decreaseof$45.5 million, or14.9 percent. Gross margin was$460.0 millionduring thethree months endedSeptember 30, 2015as compared to$449.4 millionduring the same period in2014, an increaseof$10.6 million, or2.4 percent. The below factors contributed to the change in gross margin:

	$ Change
	(In millions)
Quantity variance (primarily weather)	$	10.0
New customer growth	8.5
Non-residential demand and related revenues	3.7
Price variance (A)	2.4
Other	0.4
Industrial and oilfield sales	(2.4		)
Wholesale transmission revenue	(4.1		)
Expiration of AVEC contract (B)	(7.9		)
Change in gross margin	$	10.6

(A) Increased primarily due to sales and customer mix.

(B) On June 30, 2015, the wholesale power contract with the AVEC expired. OG&E no longer provides power to AVEC.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.Fuel expense was$148.7 millionduring thethree months endedSeptember 30, 2015as compared to$162.5 millionduring the same period in2014, a decreaseof$13.8 million, or8.5 percent, primarily due to a decrease in natural gas prices and a decrease in generation. Purchased power costs were$100.3 millionduring thethree months endedSeptember 30, 2015as compared to$134.1 millionduring the same period in2014, a decreaseof$33.8 million, or25.2 percent, primarily due to a decrease of$40.3 millionin purchases from the Integrated Market and $0.3 millionin non-wind purchase power agreements, partially offset by an increase of $3.1 millionin transmission and curtailment expenses, $2.8 millionin cogeneration purchases, and $0.9 millionin wind purchased power. Transmission expense is charged to OG&E by the SPP for the utilization of transmission systems owned by other SPP members and is recovered from retail customers through the SPP Cost Tracker in Oklahoma and through the Transmission Cost Rider in Arkansas. Transmission expenses were$10.8 millionduring thethree months endedSeptember 30, 2015as compared to$8.7 millionduring the same period in2014, an increaseof$2.1 million, or24.1 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.

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Operating Expenses

Other operation and maintenance expense was$107.4 millionduring thethree months endedSeptember 30, 2015as compared to$111.0 millionduring the same period in2014, a decreaseof$3.6 million, or3.2 percent. The below factors contributed to the change in other operation and maintenance expense:

	$ Change
	(In millions)
Maintenance at power plants (A)	$	(2.7	)
Salaries and wages (B)	(1.8		)
Injuries and damages (C)	(1.0		)
Other	(0.7		)
Employee benefits (D)	1.1
Corporate overhead and allocations (E)	1.5
Change in other operation and maintenance expense	$	(3.6	)

(A) Decreased primarily due to less work at power plants.

(B) Decreased primarily due to a decrease in incentive compensation partially offset by annual salary increases.

(C) Decreased primarily due to fewer new cases in 2015.

(D) Increased due to pension settlements.

(E) Increased due to allocations from pension settlements at the holding company.

Depreciation and amortization expense was$75.9 millionduring thethree months endedSeptember 30, 2015as compared to$69.4 millionduring the same period in2014, an increaseof$6.5 million, or9.4 percent, primarily due to additional assets being placed in service, along with an increase resulting from the amortization of the deferred pension credits regulatory liability which was fully amortized in July 2014.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was$2.2 millionduring thethree months endedSeptember 30, 2015as compared to$1.1 millionduring the same period in2014, an increase of $1.1 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other Income.Other income was $4.8 million during the three months endedSeptember 30, 2015 as compared to $2.4 million during the same period in 2014, an increase of $2.4 million, primarily due to an increase in other income from jobbing and contracting.

Interest Expense. Interest expense was$36.4 millionduring thethree months endedSeptember 30, 2015as compared to$35.3 millionduring the same period in2014, an increase of$1.1 million, 3.1 percent, primarily due to an increase in interest on long term debt related to a $250 million debt issuance that occurred in December 2014.

Income Tax Expense.Income tax expense was$63.0 millionduring thethree months endedSeptember 30, 2015as compared to$58.7 millionduring the same period in2014, an increaseof$4.3 million, or7.3 percent, primarily due to higher pretax income and a reduction in Federal tax credits recognized.

Nine Months Ended September 30, 2015as Compared toNine Months Ended September 30, 2014

OG&E's net incomedecreased$5.9 million, or2.3 percent, during thenine months endedSeptember 30, 2015as compared to the same period in2014primarily due to higher depreciation and amortization expense, higher interest expense and higher taxes other than income partially offset by higher gross margin, higher other income and lower other operation and maintenance.

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Gross Margin

Operating revenues were$1,749.8 millionduring thenine months endedSeptember 30, 2015as compared to$1,926.9 millionduring the same period in2014, a decreaseof$177.1 million, or9.2 percent. Cost of sales were$682.3 millionduring thenine months endedSeptember 30, 2015as compared to$869.6 millionduring the same period in2014, a decreaseof$187.3 million, or21.5 percent. Gross margin was$1,067.5 millionduring thenine months endedSeptember 30, 2015as compared to$1,057.3 millionduring the same period in2014, an increaseof$10.2 million, or1.0 percent. The below factors contributed to the change in gross margin:

	$ Change
	(In millions)
New customer growth	$	18.1
Price variance (A)	14.5
Non-residential demand and related revenues	4.9
Other	1.7
Industrial and oilfield sales	(3.4		)
Quantity variance (primarily weather)	(4.4		)
Expiration of AVEC Contract (B)	(7.9		)
Wholesale transmission revenue (C)	(13.3		)
Change in gross margin	$	10.2

(A) Increased primarily due to sales and customer mix.

(B) On June 30, 2015, the wholesale power contract with AVEC expired. OG&E no longer provides power to AVEC.

(C) Decreased primarily due to a true up for the base plan projects in the SPP formula rate for 2014 and for the nine months ended September 30, 2015 as well as a reduction in the point-to-point credits shared with retail customers.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.Fuel expense was$368.4 millionduring thenine months endedSeptember 30, 2015as compared to$508.8 millionduring the same period in2014, a decreaseof$140.4 million, or27.6 percent, primarily due to a decrease in natural gas prices and decreased generation.Purchased power costs were$280.9 millionduring thenine months endedSeptember 30, 2015as compared to$334.9 millionduring the same period in2014, a decreaseof$54.0 million, or16.1 percent, primarily due to a decrease of$44.4 millionin purchases from the Integrated Market$6.6 millionin cogeneration purchases,$5.2 millionin wind purchased power, $1.1 millionin Spot Market purchases, and $0.6 millionin non-wind purchase power agreements, partially offset by an increase of $3.9 millionin transmission and curtailment expenses. Transmission expense is charged to OG&E by the SPP for the utilization of transmission systems owned by other SPP members and is recovered from retail customers through the SPP Cost Tracker in Oklahoma and through the Transmission Cost Rider in Arkansas. Transmission expenses were$33.0 millionduring thenine months endedSeptember 30, 2015as compared to$25.9 millionduring the same period in2014, an increaseof$7.1 million, or27.4 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

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Operating Expenses

Other operation and maintenance expense was$337.3 millionduring thenine months endedSeptember 30, 2015as compared to$343.1 millionduring the same period in2014, a decreaseof$5.8 million, or1.7 percent. The below factors contributed to the change in other operation and maintenance expense:

	$ Change
	(In millions)
Maintenance at power plants (A)	$	(6.5	)
Additional capitalized labor (B)	(4.4		)
Vegetation management (C)	(2.0		)
Other	(0.5		)
Corporate overhead and allocations (D)	1.3
Salaries and wages (E)	2.8
Employee benefits (F)	3.5
Change in other operation and maintenance expense	$	(5.8	)

(A) Decreased primarily due to less work at the power plants.

(B) Decreased due to more capital projects.

(C) Decreased due to less tree trimming related to increased rainfall in May 2015.

(D) Increased primarily due to allocations from pension settlements at the holding company.

(E) Increased primarily due to annual salary increases partially offset by a decrease in incentive compensation.

(F) Increased primarily due to higher actual medical costs incurred.

Depreciation and amortization expense was$224.0 millionduring thenine months endedSeptember 30, 2015as compared to$198.7 millionduring the same period in2014, an increaseof$25.3 million, or12.7 percent, primarily due to additional assets being placed in service, along with an increase resulting from the amortization of the deferred pension credits and post-retirement medical regulatory liabilities which was fully amortized in July 2014 and the amortization of deferred storm costs that began April 2014.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was $5.4 million during the nine months endedSeptember 30, 2015 as compared to $3.0 million during the same period in 2014, an increase of $2.4 million, or 80.0 percent, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Taxes other than Income. Taxes other than income was $65.7 million during the nine months endedSeptember 30, 2015 as compared to $63.1 million during the same period in 2014, an increase of $2.6 million, or 4.1 percent, primarily due to increased ad valorem taxes.

Other Income.Other income was $9.8 million during the nine months endedSeptember 30, 2015 as compared to $3.0 million during the same period in 2014, an increase of $6.8 million, primarily due to increased guaranteed flat bill margins and an increase in other income from jobbing and contracting.

Interest Expense. Interest expense was $110.5 million during the nine months endedSeptember 30, 2015 as compared to $106.7 million during the same period in 2014, an increase of $3.8 million, or 3.6 percent, primarily due to an increase in interest on long term debt related to a $250 million debt issuance that occurred in March 2014 and a $250 million debt issuance that occurred in December 2014.

Income Tax Expense.Income tax expense was$94.9 millionduring thenine months endedSeptember 30, 2015as compared to$95.3 millionduring the same period in2014, a decreaseof$0.4 million, or0.4 percent, primarily due to lower pretax income and partially offset by a reduction in Federal tax credits.

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OGE Holdings (Natural Gas Midstream Operations)

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2015			2014			2015			2014
Operating revenues	$	—		$	—		$	—		$	—
Cost of sales	—			—			—			—
Other operation and maintenance	4.9			0.3			5.9			0.7
Depreciation and amortization	—			—			—			—
Taxes other than income	—			—			—			—
Operating income	(4.9		)	(0.3		)	(5.9		)	(0.7		)
Equity in earnings of unconsolidated affiliates (A)	(71.9		)	44.7			(12.0		)	131.9
Income before taxes	(76.8		)	44.4			(17.9		)	131.2
Income tax expense	(26.8		)	16.2			(8.7		)	49.6
Net income (loss) attributable to OGE Holdings	$	(50.0	)	$	28.2		$	(9.2	)	$	81.6

(A) The Company recorded a$108.4 millionpre-tax charge in thethree and nine months endedSeptember 30, 2015for its share of the goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

Three Months Ended September 30, 2015as Compared toThree Months Ended September 30, 2014

OGE Holding's net income for the three months endedSeptember 30, 2015 as compared to the same period in 2014decreased$78.2 million primarily due to a $116.6 milliondecrease in equity in earnings of Enable in addition to the $4.8 million pension settlement associated with seconded employees. The decrease in equity in earnings of Enable reflected a $116.7 million decrease in the Company's share of Enable's net income. Enable's gathering and processing business segment reported a decrease in operating income primarily from a decrease in gross margin, an increase in operation and maintenance expense, an increase in depreciation and amortization expense and an increase in taxes other than income taxes. Gathering and processing gross margin decreased primarily due to lower average natural gas prices and lower processing margin due to lower NGLs prices.  Enable's transportation and storage business segment reported a decrease in operating income primarily from a decrease in unrealized gains on natural gas derivatives, a decrease in liquid sales due to lower NGLs prices, a decrease in storage demand fees, and a decrease in transportation services partially offset by higher system optimization opportunities and an increase in off-system transportation sales.

Income Tax Expense/Benefit.Income tax benefit was$26.8 millionduring thethree months endedSeptember 30, 2015as compared toincome tax expense of$16.2 millionduring the same period in2014, a decreaseof$43.0 millionprimarily reflecting lower pretax operating income and the impact of goodwill impairment on Enable.

Nine Months Ended September 30, 2015as Compared toNine Months Ended September 30, 2014

OGE Holding's net income for the nine months endedSeptember 30, 2015 as compared to the same period in 2014decreased$90.8 million primarily due to a $143.9 milliondecrease in equity in earnings of Enable in addition to the $4.8 million pension settlement associated with seconded employees. The decrease in equity in earnings of Enable reflected a $147.0 million decrease in the Company's share of Enable's net income. Enable's gathering and processing business segment reported a decrease in operating income primarily from a decrease in gross margin,  an increase in operation and maintenance expense, an increase in depreciation and amortization expense and an increase in taxes other than income taxes. Gathering and processing gross margin decreased primarily due to lower average natural gas prices and lower processing margin due to lower NGLs prices.  Enable's transportation and storage business segment reported a decrease in operating income primarily from a decrease in unrealized gains on natural gas derivatives, a decrease in liquid sales due to lower NGLs prices, a decrease in storage demand fees and a decrease in transportation services partially offset by higher system optimization opportunities and an increase in off-system transportation sales.

Income Tax Expense/Benefit.Income tax benefit was$8.7 millionduring thenine months endedSeptember 30, 2015as compared toincome tax expense of$49.6 millionduring the same period in2014, a decreaseof$58.3 million primarily reflecting lower pretax operating income, a benefit recognized associated with a remeasurement of deferred taxes related to the Company's investment in Enable and the impact of goodwill impairment on Enable.

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Reconciliation of Equity in Earnings of Unconsolidated Affiliates

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three and nine months endedSeptember 30, 2015 as compared to the same period in 2014:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions)
OGE's share of Enable Net Income (Loss)	$	(80.3	)	$	36.4	$	(35.9	)	$	111.1
Amortization of basis difference	3.5			3.4		10.6			10.4
Elimination of Enogex Holdings fair value and other adjustments	4.9			4.9		13.3			10.4
OGE's Equity in earnings of unconsolidated affiliates	$	(71.9	)	$	44.7	$	(12.0	)	$	131.9

Enable Results of Operations

The following table represents summarized financial information of Enable for the three and nine months endedSeptember 30, 2015 as compared to the same period in 2014:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
	(In millions)
Operating revenues	$	646		$	803	$	1,852		$	2,632
Cost of sales	287			439		856			1,550
Operating income	(975		)	152		(778		)	452
Net income	(985		)	139		(817		)	408

Enable Operating Data

The following table presents Enable's operating data for the three and nine months endedSeptember 30, 2015 as compared to the same period in 2014:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2015	2014	2015	2014
Gathered volumes - TBtu/d	3.17	3.32	3.17	3.34
Transportation volumes - TBtu/d	4.62	4.55	5.10	5.02
Natural gas processed volumes - TBtu/d	1.87	1.60	1.79	1.52
NGLs sold - million gallons/d (A)(B)	81.63	68.86	74.45	69.61

(A) Excludes volumes billed under throughput agreements.

(B) Excludes condensate. Includes third party processing.

Off-Balance Sheet Arrangement

There have been no significant changes in the Company's off-balance sheet arrangement from that discussed in the Company's 2014Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

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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 Cash and Cash Equivalents was $43.3 million and $5.5 million at September 30, 2015 and December 31, 2014, respectively, an increase of $37.8 million, primarily due to normal business operations which includes the quarterly distributions received from Enable.

The balance of Accounts Receivable and Accrued Unbilled Revenues was$305.6 millionand$249.9 millionatSeptember 30, 2015andDecember 31, 2014, respectively,an increaseof$55.7 million, or22.3 percent, primarily due toan increase in billings to OG&E's retail customers reflecting higher seasonal rates in September 2015 as compared to December 2014.

The balance of Fuel Inventories was $86.2 million and $58.5 million at September 30, 2015 and December 31, 2014, respectively, an increase of $27.7 million, or 47.4 percent, primarily due to higher coal inventory balances at OG&E's coal fired plants resulting from increased deliveries and higher average prices in the nine months ended September 2015 as compared to December 2014.

The balance of Fuel Clause Under Recoveries was $1.6 million and $68.3 million at September 30, 2015 and December 31, 2014, respectively, a decrease of $66.7 million, or 97.7 percent, primarily due to higher amounts billed to OG&E retail customers as compared to the actual cost of fuel and purchased power in addition to amortization of the prior year's under recovery balance, resulting in the movement of the Oklahoma jurisdiction to an over-recovery position of $34.5 million at the close of the third quarter. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs when the actual fuel and purchased power cost recoveries exceed fuel adjustment clause recoveries and over recovers fuel costs when the actual fuel and purchased power costs are below the fuel adjustment clause recoveries. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances into future cost recoveries.

The balance of Short-term Debt was $98.0 million at December 31, 2014 with no balance at September 30, 2015, primarily due to the payoff of all commercial paper mainly from normal business operations which includes the quarterly distributions from Enable.

The balance of Accounts Payable was $125.7 million and $179.1 million at September 30, 2015 and December 31, 2014, respectively, a decrease of $53.4 million, or 29.8 percent, primarily due to the timing of vendor payments and a decrease in accruals.

The balance of Accrued Taxes was $61.4 million and $39.7 million at September 30, 2015 and December 31, 2014, respectively, an increase of $21.7 million, or 54.7 percent, primarily due to ad valorem tax accruals and payments, and current federal tax accruals partially offset by tax deductions related to equity based compensation.

The balance of Long-term Debt Due Within One Year was $110.0 million as of September 30, 2015 compared to no balance at December 31, 2014primarily due to the reclassification of long-term debt that will mature in January 2016.

Cash Flows

	Nine Months Ended
	September 30,						2015 vs. 2014
(In millions)	2015			2014			$ Change			% Change
Net cash provided from operating activities	$	609.1		$	466.5		$	142.6		30.6	%
Net cash used in investing activities	(335.9		)	(427.3		)	91.4			21.4	%
Net cash provided from (used in) financing activities	(235.4		)	(46.0		)	(189.4		)	*

* Change is greater than 100%.

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Operating Activities

Theincrease of $142.6 million, or 30.6 percent, in net cash provided from operating activities during thenine months endedSeptember 30, 2015as compared to the same period in2014was primarily due toan increase in cash received from fuel recoveries at OG&E.

Investing Activities

Thedecrease of $91.4 million, or 21.4 percent, in net cashused ininvesting activities during thenine months endedSeptember 30, 2015as compared to the same period in2014was primarily due toa decrease in capital expenditures related to transmission projects partially offset by an increase in capital expenditures related to environmental projects at OG&E.

Financing Activities

Theincrease of $189.4 millionin net cash used in financing activitiesduring thenine months endedSeptember 30, 2015as compared to the same period in2014was primarily due to the issuance of $250 million in long-term debt during the first quarter of 2014, an increase in short-term debt and an increase in dividends paid partially offset by the payment of $140 million in long-term debt during the third quarter of 2014.

Future Capital Requirements and Financing Activities

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Capital Expenditures

The Company's consolidated estimates of capital expenditures for the years 2015 through 2019 are shown in the following table.These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company's business) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included in the table below.

(In millions)	2015		2016		2017		2018		2019
OG&E Base Transmission	$	50	$	55	$	30	$	30	$	30
OG&E Base Distribution	165		195		175		175		175
OG&E Base Generation	90		60		75		75		75
OG&E Other	65		40		25		25		25
Total Base Transmission, Distribution, Generation and Other	370		350		305		305		305
OG&E Known and Committed Projects:
Transmission Projects:
Other Regionally Allocated Projects (A)	15		50		20		20		20
Large SPP Integrated Transmission Projects (B) (C)	30		35		25		10		60
Total Transmission Projects	45		85		45		30		80
Other Projects:
Environmental - low NOX burners (D)	25		20		10		—		—
Environmental - activated carbon injection (D)	20		—		—		—		—
Environmental - natural gas conversion (D)	—		—		—		40		35
Environmental - scrubbers (D)	80		150		140		95		20
Combustion turbines - Mustang Modernization	55		180		100		50		5
Total Other Projects	180		350		250		185		60
Total Known and Committed Projects	225		435		295		215		140
Total	$	595	$	785	$	600	$	520	$	445

(A) Typically 100kV to 299kV projects. Approximately 30% of revenue requirement allocated to SPP members other than OG&E.

(B) Typically 300kV and above projects. Approximately 85% of revenue requirement allocated to SPP members other than OG&E.

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(C)	Project Type	Project Description	Estimated Cost (In millions)	Projected In-Service Date
	Integrated Transmission Project	30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation	$45	Early 2018
	Integrated Transmission Project	126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation; construction of the Mathewson substation on this transmission line	$180	Early 2021

(D) Represent capital costs associated with OG&E’s Environmental Compliance Plan to comply with the EPA’s MATS and Regional Haze rules. More detailed discussion regarding Regional Haze and OG&E’s Environmental Compliance Plan can be found in Note 13 of Notes to Condensed Financial Statements under "Environmental Compliance Plan" in Item 1 of Part I of this Form 10-Q, and under “Environmental Laws and Regulations” within “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Part I, Item 2 of this Form 10-Q.

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based on 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 by itself 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.

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

Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt, distributions from equity method investments and proceeds from the sales ofcommon stock to the public through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings and distributions from Enable will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. The Company utilizes short-term borrowings (through a combination of bank borrowings 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 September 30, 2015, the Company has revolving credit facilities totaling in the aggregate $1,150.0 million. These bank facilities can also be used asletter of credit facilities. The short-term debt balance was$98.0 millionatDecember 31, 2014, with no balance at September 30, 2015. The average balance of short-term debt during the nine months endedSeptember 30, 2015 was $100.5 million at a weighted-average interest rate of 0.46 percent. The maximum month-end balance of short-term debt during the nine months endedSeptember 30, 2015 was $180.0 million. AtSeptember 30, 2015, there were$1.9 millionsupporting letters of credit at a weighted-average interest rate of0.95 percent. At September 30, 2015, the Company had $1,148.1 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, 2015 and ending December 31, 2016.  At September 30, 2015, the Company had $43.3 million in cash and cash equivalents.  See Note9of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

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Quarterly Distributions by Enable

Pursuant to the Enable Agreement, during the three and nine months ended Enable made distributions of approximately $35.1 million and $104.0 million, respectively, to the Company.

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis.In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could have a material effect on the Company's Condensed Consolidated Financial Statements.  However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.

In management's opinion, the areas of the Company where the most significant judgment is exercised for all Company segments includes the determination of Pension Plan assumptions, estimates of equity method investments and income taxes. For the electric utility segment, significant judgment is also exercised in contingency reserves, asset retirement obligations, the allowance for uncollectible accounts and the valuation of regulatory assets and liabilities and unbilled revenues. 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 2014Form 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, 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. See Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q for a discussion of the Company's commitments and contingencies.

Environmental Laws and Regulations

The activities of OG&E are subject to numerous, stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards. These environmental laws and regulations are discussed in detail in Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's 2014Form 10-K. Except as set forth below, there have been no material changes to such items.

OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a pre-approval plan to handle state and Federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E's retail customers under House Bill 1910, which was enacted into law in May 2005.

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Air

Regional Haze Control Measures

The EPA's 2005 regional haze rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States that may be impacted by air pollutant emissions.

On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the regional haze rule. The SIP was subject to the EPA's review and approval.

The Oklahoma SIP included requirements for reducing emissions of NO_X and SO₂from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NO_Xemissions at all of the subject units should be the installation of low NO_Xburners with overfire air (flue gas recirculation was also required on two of the units) and set forth associated NO_Xemission rates and limits.

On December 28, 2011, the EPA issued a final rule in which it rejected the SO₂portion of the Oklahoma SIP and issued a FIP in its place.OG&E and the State of Oklahoma's subsequent appeal of the FIP with the Tenth Circuit of Appeals and the U.S. Supreme Court ended on May 27, 2014 when the Supreme Court denied Petition for Certiorari, upholding the EPA's FIP for SO₂. The FIP compliance date is now January 4, 2019.

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance and Mustang Modernization Plan included in this application to be approximately$1.1 billion. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

As previously reported, on June 8, 2015 the ALJ issued his report on OG&E's application. While the ALJ in his report agrees that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s environmental compliance plan is the best approach, the ALJ makes various recommendations including, among others, that: (i) the OCC should not raise rates at this time; (ii) with respect to OG&E’s environmental compliance plan, the OCC should grant pre-approval of the estimated costs for new equipment as set by contract, including installation costs covered by a contract, but pre-approval of other equipment and installation costs that were still being negotiated at the end of the evidentiary hearing on April 8, 2015 should be deferred and may be considered in the next general rate case; (iii) the foregoing pre-approval is subject to the condition that the OCC should direct OG&E to issue requests for information for at least 200 MWs of wind power within thirty days of a final order; (iv) the OCC should postpone consideration of all other cost recovery issues until the next general rate case; (v) the OCC should direct the PUD Director to commence a general rate case; and (vi) the OCC should deny the Mustang Modernization Plan. OG&E filed exceptions to the ALJ's report in which OG&E set forth the various findings and recommendations that OG&E believes to be erroneous, including the ALJ’s refusal to recommend a recovery rider for OG&E environmental compliance plan and the ALJ’s recommendation that the OCC should deny the Mustang Modernization Plan. The OCC heard oral arguments on June 25, 2015 and took the case under advisement. On July 21, 2015, Commissioner Bob Anthony (one of the three commissioners on the OCC) issued his deliberation statement that was consistent with many parts of the ALJ Report, including the ALJ’s support of OG&E’s environmental compliance plan, the ALJ’s recommendation, as described above, to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other costs recovery issues until the next general rate case. OG&E cannot predict the outcome of this proceeding.

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

On July 8, 2013, the U.S. Department of Justice, filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission

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increases attributable to eight projects that occurred between 2003 and 2006. The Sierra Club intervened in this proceeding. On September 6, 2013, OG&E filed a Motion to Dismiss the case.  On January 15, 2015, U.S. District Judge Timothy DeGuisti dismissed the complaints filed by the EPA and Sierra Club.  The Court held that it lacked subject matter jurisdiction over the Plaintiffs’ claims because Plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution.   The court also ruled in the alternative that, even if the Plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.”  The EPA and the Sierra Club did not file an appeal of the Court’s ruling.

On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008, were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the Eastern District dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the Eastern District to dismiss its remaining claims with prejudice. On August 27, 2014, the Eastern District granted the Sierra Club's request. The Sierra Club has filed a Notice of Appeal with the 10th Circuit where oral argument was held on March 18, 2015.

At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act, and OG&E expects to vigorously defend against the claims that have been asserted. If OG&E does not prevail in the remainder of the proceedings, the Sierra Club could seek to require OG&E to install additional pollution control equipment at Muskogee 6, including scrubbers, baghouses and selective catalytic reduction systemsand pay fines and significant penalties as a result of the allegations. 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. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, the Company could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of the end of 2014, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect the Company's operations.

On March 2, 2015, the U.S. District Court for the Northern District of California issued an order granting the EPA and the Sierra Club's joint motion to approve and enter a consent decree that required the EPA to promulgate and publish the remaining area designations for the 2010 SO₂ standard. On September 18, 2015 the Oklahoma Department of Environmental Quality reported to the EPA that no areas in Oklahoma should be designated as non-attainment for the 2010 SO₂ standard. This non-attainment designation is subject to the EPA's approval.

On September 30, 2015 the EPA finalized a new ambient standard for ozone at 70 ppb which is more stringent than the current standard of 75 ppb, set in 2008. States must submit non-attainment designations as appropriate based on existing ambient data before October, 2016 for the EPA’s approval. Compliance with the new standard begins in 2020 or later depending on the degree of the area’s non-attainment designation. All areas in Oklahoma currently meet the new standard.

The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.

Hazardous Air Pollutants Emission Standards

On April 16, 2012, regulations governing emissions of certain hazardous air pollutants from electric generating units were published as the final MATS rule.  This rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. Compliance is required within three years after the effective date of the rule with the possibility of a one-year extension. OG&E requested and received a one-year extension for complying or until April 16, 2016. To comply with this rule, OG&E is currently planning to utilize activated carbon injection at each of its five coal-fired units.

42

The final MATS rule was appealed by several parties, but OG&E was not a party to the appeals.  After withstanding judicial scrutiny at the District of Columbia Circuit Court of Appeals, the MATS rule was challenged at the U.S. Supreme Court.  On June 29, 2015, the U.S. Supreme Court found that the EPA should have considered the compliance costs imposed on utilities at the first stage of the Agency’s regulatory analysis.  The U.S. Supreme Court did not vacate the rule, but reversed the D.C. Circuit and remanded to the D.C. Circuit for further proceedings.  The MATS rule currently remains in effect and OG&E is still required to meet the April 2016 compliance deadline unless the D.C. Circuit vacates the rule or grants some other relief from the compliance mandate.     

Clean Power Plan

On August 3, 2015, the EPA issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates.  The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan.  The EPA has given states the option to develop compliance plans for annual rate-based reductions (lb/MWh) or mass-based tonnage limits for CO₂.  The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed43 percentreduction to32 percentin the final rule.  The mass-based approach for existing units calls for a24 percentreduction by 2030 in Oklahoma.  The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission.  The compliance period begins in 2022, and emission reductions will be phased in to 2030.  The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan is not submitted to the EPA.  OG&E is currently evaluating the Clean Power Plan rules and is working in collaboration with the State of Oklahoma on OG&E's plans.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

There have been no significant changes in the market risks affecting the Company from those discussed in the Company's 2014 Form 10-K.

Item 4.  Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure.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).

43

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2014Form 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.

There have been no significant changes in the Company's risk factors from those discussed in the Company's 2014Form 10-K, which are incorporated herein by reference.

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 third quarter of 2015.

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
07/01/15 - 07/30/15	167	(A)	$	28.76	N/A	N/A
08/01/15 - 08/31/15	—		$	—	N/A	N/A
09/01/15 - 09/30/15	745		$	26.85	N/A	N/A

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

Item 6.  Exhibits.

Exhibit No.	Description
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.PRE	XBRL Taxonomy Presentation Linkbase Document.
101.LAB	XBRL Taxonomy Label Linkbase Document.
101.CAL	XBRL Taxonomy Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

44

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)

November 5, 2015

45

EX-31.01

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: November 5, 2015

  /s/ Sean Trauschke

Sean Trauschke

President and Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, Stephen Merrill, 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: November 5, 2015

  /s/ Stephen Merrill

Stephen Merrill

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 endedSeptember 30, 2015, 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.

November 5, 2015

          /s/ Sean Trauschke

               Sean Trauschke

President and Chief Executive Officer

          /s/ Stephen Merrill

               Stephen Merrill

Chief Financial Officer

XML

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) Reclassifications out of AOCI (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ (4.4)	$ (0.3)	$ (5.3)	$ (0.9)
Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	[1]	(1.0)	(0.8)	(3.6)	(2.3)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Settlement Cost, before Tax	[1]	(6.2)	0.0	(6.2)	0.0
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(7.2)	(0.8)	(9.8)	(2.3)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		(2.7)	(0.3)	(4.1)	(0.9)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(4.5)	(0.5)	(5.7)	(1.4)
Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	[1]	(0.5)	(0.2)	(1.5)	(1.0)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	[1]	0.7	0.6	2.1	2.1
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		0.2	0.4	0.6	1.1
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		0.1	0.1	0.2	0.4
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		0.1	0.3	0.4	0.7
Derivative [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		0.0	(0.1)	0.0	(0.3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax		0.0	0.0	0.0	(0.1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0.0	(0.1)	0.0	(0.2)
Interest Expense [Member] | Interest Rate Swap [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		$ 0.0	$ (0.1)	$ 0.0	$ (0.3)

[1] These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

XML

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating revenues	$ 719.8		$ 754.7		$ 1,749.8		$ 1,926.9
Cost of sales	259.8		305.3		682.3		869.6
Other operation and maintenance	109.4		108.1		334.3		331.9
Depreciation and amortization	77.9		71.7		230.0		207.2
Taxes other than income	21.9		21.5		68.8		66.5
OPERATING INCOME	250.8		248.1		434.4		451.7
Equity in earnings of unconsolidated affiliates (A)	(71.9)	[1]	44.7	[1]	(12.0)	[2]	131.9	[2]
Other income (expense)	5.8		2.5		16.3		3.5
Interest expense	37.0		37.2		112.4		112.5
Income tax expense	36.5		70.8		84.4		137.2
Net income (loss)	111.2		187.3		241.9		337.4
Investment in unconsolidated affiliates	1,202.2		1,311.1		1,202.2		1,311.1		$ 1,318.2
Total assets	9,617.8		9,462.7		9,617.8		9,462.7		$ 9,527.8
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	719.8		754.7		1,749.8		1,926.9
Cost of sales	259.8		305.3		682.3		869.6
Other operation and maintenance	107.4		111.0		337.3		343.1
Depreciation and amortization	75.9		69.4		224.0		198.7
Taxes other than income	21.0		20.6		65.7		63.1
OPERATING INCOME	255.7		248.4		440.5		452.4
Equity in earnings of unconsolidated affiliates (A)	0.0	[1]	0.0	[1]	0.0	[2]	0.0	[2]
Other income (expense)	6.6		2.9		13.9		4.5
Interest expense	36.4		35.3		110.5		106.7
Income tax expense	63.0		58.7		94.9		95.3
Net income (loss)	162.9		157.3		249.0		254.9
Investment in unconsolidated affiliates	0.0		0.0		0.0		0.0
Total assets	8,570.7		8,003.1		8,570.7		8,003.1
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0		0.0		0.0		0.0
Cost of sales	0.0		0.0		0.0		0.0
Other operation and maintenance	4.9		0.3		5.9		0.7
Depreciation and amortization	0.0		0.0		0.0		0.0
Taxes other than income	0.0		0.0		0.0		0.0
OPERATING INCOME	(4.9)		(0.3)		(5.9)		(0.7)
Equity in earnings of unconsolidated affiliates (A)	(71.9)	[1]	44.7	[1]	(12.0)	[2]	131.9	[2]
Other income (expense)	0.0		0.0		0.0		0.0
Interest expense	0.0		0.0		0.0		0.0
Income tax expense	(26.8)		16.2		(8.7)		49.6
Net income (loss)	(50.0)		28.2		(9.2)		81.6
Investment in unconsolidated affiliates	1,202.2		1,311.1		1,202.2		1,311.1
Total assets	1,541.5		1,427.2		1,541.5		1,427.2
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0		0.0		0.0		0.0
Cost of sales	0.0		0.0		0.0		0.0
Other operation and maintenance	(2.9)		(3.2)		(8.9)		(11.9)
Depreciation and amortization	2.0		2.3		6.0		8.5
Taxes other than income	0.9		0.9		3.1		3.4
OPERATING INCOME	0.0		0.0		(0.2)		0.0
Equity in earnings of unconsolidated affiliates (A)	0.0	[1]	0.0	[1]	0.0	[2]	0.0	[2]
Other income (expense)	(0.7)		(0.3)		2.6		(0.8)
Interest expense	0.7		2.0		2.1		6.0
Income tax expense	0.3		(4.1)		(1.8)		(7.7)
Net income (loss)	(1.7)		1.8		2.1		0.9
Investment in unconsolidated affiliates	0.0		0.0		0.0		0.0
Total assets	134.0		204.1		134.0		204.1
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0		0.0		0.0		0.0
Cost of sales	0.0		0.0		0.0		0.0
Other operation and maintenance	0.0		0.0		0.0		0.0
Depreciation and amortization	0.0		0.0		0.0		0.0
Taxes other than income	0.0		0.0		0.0		0.0
OPERATING INCOME	0.0		0.0		0.0		0.0
Equity in earnings of unconsolidated affiliates (A)	0.0	[1]	0.0	[1]	0.0	[2]	0.0	[2]
Other income (expense)	(0.1)		(0.1)		(0.2)		(0.2)
Interest expense	(0.1)		(0.1)		(0.2)		(0.2)
Income tax expense	0.0		0.0		0.0		0.0
Net income (loss)	0.0		0.0		0.0		0.0
Investment in unconsolidated affiliates	0.0		0.0		0.0		0.0
Total assets	(628.4)		$ (171.7)		(628.4)		$ (171.7)
OGE Energy [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss	$ 108.4				$ 108.4

[1] The Company recorded a $108.4 million pre-tax charge during the three months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

[2] The Company recorded a $108.4 million pre-tax charge during the nine months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

XML

Income Taxes (Details) $ in Millions	3 Months Ended
	Sep. 30, 2015 USD ($)
Unrecognized Tax Benefits, Period Increase (Decrease)	$ 3.8
State and Local Jurisdiction [Member]
Unrecognized Tax Benefits, Period Increase (Decrease)	$ 2.4

XML

Commitments and Contingencies (Details) - USD ($)	Sep. 30, 2015	Jun. 15, 2015
Long-term Purchase Commitment [Line Items]
Contract Amount		$ 170,300,000
New Source Review [Member]
Long-term Purchase Commitment [Line Items]
Potential Penalty Under the Federal Clean Air Act	$ 37,500
Clean Power Plan [Member]
Long-term Purchase Commitment [Line Items]
Proposed Rate-Based Carbon Reduction	43.00%
Final Rate-Based Carbon Reduction	32.00%
Mass-Based Carbon Reduction	24.00%

XML

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 2,510.0	$ 2,509.7
Long-Term Debt, Fair Value	2,800.5	2,957.7
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	10.1	10.2
Long-Term Debt, Fair Value	9.3	10.3
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	100.0	100.0
Long-Term Debt, Fair Value	$ 99.9	$ 99.9

XML

Retirement Plans and Postretirement Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2015

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, before consideration of capitalized amounts, 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						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)			2015 (B)		2014 (B)		2015 (C)		2014 (C)
Service cost	$	4.2		$	3.9		$	12.1		$	11.5		$	0.4	$	0.3	$	1.0	$	0.8
Interest cost	6.6			7.0			19.6			21.1			0.2		0.2		0.5		0.5
Expected return on plan assets	(11.0		)	(11.3		)	(34.5		)	(34.0		)	—		—		—		—
Amortization of net loss	3.8			3.6			13.5			10.7			0.2		0.1		0.5		0.2
Amortization of unrecognized prior service cost (A)	0.1			0.4			0.3			1.3			—		—		0.1		0.1
Settlement	16.2			—			16.2			—			—		—		—		—
Total net periodic benefit cost	19.9			3.6			27.2			10.6			0.8		0.6		2.1		1.6
Less: Amount paid by unconsolidated affiliates	1.0			0.9			3.1			2.6			—		—		0.1		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	18.9		$	2.7		$	24.1		$	8.0		$	0.8	$	0.6	$	2.0	$	1.5

(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$19.7 millionand$3.3 millionof net periodic benefit cost recognizedduring thethree months endedSeptember 30, 2015and2014, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedSeptember 30, 2015and2014of$2.7 millionand$2.8 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thethree months endedSeptember 30, 2015 of $7.4 millionrelated tothe pension settlement charge of$16.2 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thethree months endedSeptember 30, 2015 of $1.4 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$16.2 million.

(C) In addition to the$26.1 millionand$9.5 millionof net periodic benefit cost recognizedduring thenine months endedSeptember 30, 2015and2014, respectively, OG&E recognized the following:

• an increase in pension expense during thenine months endedSeptember 30, 2015and2014of$8.0 millionand$8.4 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);

• a deferral of pension expense during thenine months endedSeptember 30, 2015 of $7.4 millionrelated tothe pension settlement charge of$16.2 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thenine months endedSeptember 30, 2015 of $1.4 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$16.2 million.

	Postretirement Benefit Plans
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)
Service cost	$	0.4		$	0.7		$	1.2		$	2.3
Interest cost	2.6			2.8			7.7			8.5
Expected return on plan assets	(0.6		)	(0.6		)	(1.8		)	(1.8		)
Amortization of net loss	3.5			3.1			10.4			9.3
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)	(12.4		)	(12.4		)
Total net periodic benefit cost	1.8			1.9			5.1			5.9
Less: Amount paid by unconsolidated affiliates	0.4			0.3			1.0			1.0
Net periodic benefit cost (net of unconsolidated affiliates)	$	1.4		$	1.6		$	4.1		$	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$1.4 millionand$1.6 millionof net periodic benefit cost recognizedduring thethree months endedSeptember 30, 2015and2014, respectively, OG&E recognized an increase in postretirement medical expense duringthethree months endedSeptember 30, 2015and2014of$1.4 millionand$1.3 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1).

(C) In addition to the$4.1 millionand$4.9 millionof net periodic benefit cost recognizedduring thenine months endedSeptember 30, 2015and2014, respectively, OG&E recognized an increase in postretirement medical expense duringthenine months endedSeptember 30, 2015and2014of$4.3 millionand$3.9 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).

Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2015		2014		2015		2014
Capitalized portion of net periodic pension benefit cost	$	2.6	$	0.9	$	4.6	$	2.6
Capitalized portion of net periodic postretirement benefit cost	0.5		0.5		1.4		1.5

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

9 Months Ended

Sep. 30, 2015

Summarized Financial Information of Equity Method Investment [Line Items]

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

Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2015 and December 31, 2014 and for the three and nine months endedSeptember 30, 2015 and 2014.

Balance Sheet	September 30, 2015		December 31, 2014
	(In millions)
Current assets	$	427	$	438
Non-current assets	10,774		11,399
Current liabilities	804		671
Non-current liabilities	2,786		2,344

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Common Equity Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Equity [Abstract]
Net Income	$ 111.2	$ 187.3	$ 241.9	$ 337.4
Basic average common shares outstanding	199.7	199.3	199.6	199.1
Contingently issuable shares (performance and restricted stock units)	0.0	0.9	0.0	0.8
Diluted average common shares outstanding	199.7	200.2	199.6	199.9
Earnings Per Share, Basic and Diluted [Abstract]
Basic Earnings Per Average Common Share	$ 0.55	$ 0.94	$ 1.21	$ 1.69
Diluted Earnings Per Average Common Share	$ 0.55	$ 0.94	$ 1.21	$ 1.69
Anti-dilutive shares excluded from earnings per share calculation	0.0	0.0	0.0	0.0

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Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 427.0	$ 438.0
Non-current assets	10,774.0	11,399.0
Current liabilities	804.0	671.0
Non-current liabilities	$ 2,786.0	$ 2,344.0

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Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1		$ 58.6	$ 55.2
Liabilities settled	[1]	(0.4)	(0.2)
Accretion expense		1.9	1.9
Revisions in estimated cash flows	[2]	1.6	1.7
Balance at September 30		$ 61.7	$ 58.6

[1] In 2015, asset retirement obligations were settled for the asbestos abatement at one of OG&E's generating facilities.

[2] Assumptions changed related to the estimated cost of removal for one of OG&E's generating facilities.

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Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Short-term debt		$ 0.0	$ 98.0
Line of Credit Facility [Abstract]
Aggregate Commitment		1,150.0
Amount Outstanding	[1]	$ 1.9
Weighted Average Interest Rate		0.95%
OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[2]	$ 750.0
Amount Outstanding	[1],[2]	$ 0.0
Weighted Average Interest Rate	[2],[3]	0.00%
Maturity		Dec. 13, 2018
OG&E [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[4]	$ 400.0
Letters of Credit Outstanding, Amount	[1],[4]	$ 1.9
Weighted Average Interest Rate	[3],[4]	0.95%
Maturity		Dec. 13, 2018
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800.0
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years

[1] Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2015.

[2] This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

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

[4] This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

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Stock-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Stock-Based Compensation Activity
Income tax benefit	$ 0.5	$ 0.6	$ 2.3	$ 2.2
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	1.1	2.1	6.0	8.1
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	0.0	0.0	0.1	0.1
Stock Compensation Plan [Member]
Stock-Based Compensation Activity
Compensation expense	1.1	2.1	6.1	8.2
Less: Amount paid by unconsolidated affiliates	(0.2)	0.6	0.3	2.5
Net compensation expense	$ 1.3	1.5	$ 5.8	5.7
Common Stock
Stock-Based Compensation Activity
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	912		81,865
Restricted Stock [Member]
Stock-Based Compensation Activity
Shares Paid for Tax Withholding for Share Based Compensation	0		1,070
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 1.9	2.0	$ 5.7	5.9
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ (0.8)	$ 0.1	$ 0.3	$ 2.2

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments:  (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and has the ability to exercise significant influence.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operationsare conducted through OG&E andare subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company.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.

The natural gas midstream operations segment currently represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

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

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 atSeptember 30, 2015andDecember 31, 2014, the results of its operations for the three and nine months endedSeptember 30, 2015and2014 and the results of its cash flows for thenine months endedSeptember 30, 2015and2014, 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 thethree and nine months endedSeptember 30, 2015are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2015or 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 2014Form 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.

Certain prior-year amounts have been reclassified to conform with the current year presentation.

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 refunded in future rates.

The following table is a summary of OG&E's regulatory assets and liabilities at:

(In millions)	September 30, 2015		December 31, 2014
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	30.3	$	19.7
Fuel clause under recoveries	1.6		68.3
Other (A)(C)	9.8		10.2
Total Current Regulatory Assets	$	41.7	$	98.2
Non-Current
Benefit obligations regulatory asset	$	241.6	$	261.1
Income taxes recoverable from customers, net	55.7		56.1
Smart Grid	43.7		43.9
Deferred storm expenses	16.6		17.5
Unamortized loss on reacquired debt	15.1		16.1
Other (C)	17.0		15.7
Total Non-Current Regulatory Assets	$	389.7	$	410.4
Regulatory Liabilities
Current
Crossroads wind farm rider over recovery (B)	$	7.2	$	10.3
Smart Grid rider over recovery (B)	5.3		12.5
Fuel clause over recoveries	34.5		—
Other (B)	2.2		1.6
Total Current Regulatory Liabilities	$	49.2	$	24.4
Non-Current
Accrued removal obligations, net	$	257.1	$	248.1
Pension tracker	19.9		14.9
Total Non-Current Regulatory Liabilities	$	277.0	$	263.0

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

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

(C) Prior year amount of$1.1 millionreclassified from Non-Current Other assets to Current Other assets.

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.

Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. As discussed above, OGE Energy accounts for the investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. OGE Energy's maximum exposure to loss related to Enable is limited to OGE Energy's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at September 30, 2015. The Company evaluates its equity method investment for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment, and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment which are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during thenine months endedSeptember 30, 2015and2014.

	Nine Months Ended September 30,
(In millions)	2015			2014
Balance at January 1	$	58.6		$	55.2
Liabilities settled (A)	(0.4		)	(0.2		)
Accretion expense	1.9			1.9
Revisions in estimated cash flows (B)	1.6			1.7
Balance at September 30	$	61.7		$	58.6

(A) In 2015, asset retirement obligations were settled for the asbestos abatement at one of OG&E's generating facilities.

(B) Assumptions changed related to the estimated cost of removal for one of OG&E's generating facilities.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the nine months endedSeptember 30, 2015. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan							Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Settlement cost		Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1	$	—	$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9			—		3.8		0.9			(1.3		)	5.3
Net current period other comprehensive income (loss)	1.9			—		3.8		0.9			(1.3		)	5.3
Balance at September 30, 2015	$	(34.9	)	$	0.1	$	3.8	$	(7.1	)	$	2.0		$	(36.1	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and nine months endedSeptember 30, 2015 and 2014.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015			2014			2015			2014
Losses on cash flow hedges
Interest rate swap	$	—		$	(0.1	)	$	—		$	(0.3	)	Interest expense
	—			(0.1		)	—			(0.3		)	Total before tax
	—			—			—			(0.1		)	Tax benefit
	$	—		$	(0.1	)	$	—		$	(0.2	)	Net of tax
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.0	)	$	(0.8	)	$	(3.6	)	$	(2.3	)	(A)
Settlement cost	(6.2		)	—			(6.2		)	—			(A)
	(7.2		)	(0.8		)	(9.8		)	(2.3		)	Total before tax
	(2.7		)	(0.3		)	(4.1		)	(0.9		)	Tax benefit
	$	(4.5	)	$	(0.5	)	$	(5.7	)	$	(1.4	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	(0.5	)	$	(0.2	)	$	(1.5	)	$	(1.0	)	(A)
Prior service credit	0.7			0.6			2.1			2.1			(A)
	0.2			0.4			0.6			1.1			Total before tax
	0.1			0.1			0.2			0.4			Tax (benefit) expense
	$	0.1		$	0.3		$	0.4		$	0.7		Net of tax
Total reclassifications for the period	$	(4.4	)	$	(0.3	)	$	(5.3	)	$	(0.9	)	Net of tax

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

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Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Operating revenues	$ 646.0	$ 803.0	$ 1,852.0	$ 2,632.0
Cost of sales	287.0	439.0	856.0	1,550.0
Operating income	(975.0)	152.0	(778.0)	452.0
Net income	$ (985.0)	$ 139.0	$ (817.0)	$ 408.0

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2015

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 thethree and nine months endedSeptember 30, 2015 and 2014related to the Company's performance units and restricted stock.

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Performance units
Total shareholder return	$	1.9		$	2.0	$	5.7	$	5.9
Earnings per share	(0.8		)	0.1		0.3		2.2
Total performance units	1.1			2.1		6.0		8.1
Restricted stock	—			—		0.1		0.1
Total compensation expense	1.1			2.1		6.1		8.2
Less: Amount paid by unconsolidated affiliates	(0.2		)	0.6		0.3		2.5
Net compensation expense	$	1.3		$	1.5	$	5.8	$	5.7
Income tax benefit	$	0.5		$	0.6	$	2.3	$	2.2

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

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

The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2015 and December 31, 2014.

	September 30, 2015				December 31, 2014
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,510.0	$	2,800.5	$	2,509.7	$	2,957.7
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.1		9.3		10.2		10.3
OGE Energy Senior Notes	100.0		99.9		100.0		99.9

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Rate Matters and Regulation Rate Matters and Regulation (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
SmartHours Program [Member]
Lost Revenue Associated with Customer Programs	$ 11.1	$ 11.6	$ 10.1
SmartHours Program [Member] | Oklahoma Public Utility Division Staff [Member]
Lost Revenue Associated with Customer Programs			4.9
Reduction of Revenue			$ 5.2
Regional Haze [Member]
Estimated Environmental Capital Costs	$ 1,100.0

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Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
OGE's share of Enable Net Income (Loss)	$ (80.3)		$ 36.4		$ (35.9)		$ 111.1
Amortization of basis difference	3.5		3.4		10.6		10.4
Elimination of Enogex Holdings fair value and other adjustments	4.9		4.9		13.3		10.4
OGE's Equity in earnings of unconsolidated affiliates	$ (71.9)	[1]	$ 44.7	[1]	$ (12.0)	[2]	$ 131.9	[2]

[1] The Company recorded a $108.4 million pre-tax charge during the three months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

[2] The Company recorded a $108.4 million pre-tax charge during the nine months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

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Common Equity (Tables)

9 Months Ended

Sep. 30, 2015

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 September 30,				Nine Months Ended September 30,
(In millions except per share data)	2015		2014		2015		2014
Net Income	$	111.2	$	187.3	$	241.9	$	337.4
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.3		199.6		199.1
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—		0.9		—		0.8
Diluted average common shares outstanding	199.7		200.2		199.6		199.9
Basic Earnings Per Average Common Share	$	0.55	$	0.94	$	1.21	$	1.69
Diluted Earnings Per Average Common Share	$	0.55	$	0.94	$	1.21	$	1.69
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2015

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)
0.05%	-	0.13%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.06%	-	0.19%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.14%	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	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2013	$ 3,037.1	$ 2.0	$ 1,071.6	$ 1,991.7	$ (28.2)
Changes in Stockholders' Equity
Net income	337.4	0.0	0.0	337.4	0.0
Other comprehensive income, net of tax	0.9	0.0	0.0	0.0	0.9
Dividends declared on common stock	(139.5)	0.0	0.0	(139.5)	0.0
Issuance of common stock	10.1	0.0	10.1	0.0	0.0
Stock-based compensation	(3.0)	0.0	(3.0)	0.0	0.0
Balance at Sep. 30, 2014	3,243.0	2.0	1,078.7	2,189.6	(27.3)
Balance at Dec. 31, 2014	3,244.4	2.0	1,085.6	2,198.2	(41.4)
Changes in Stockholders' Equity
Net income	241.9	0.0	0.0	241.9	0.0
Other comprehensive income, net of tax	5.3	0.0	0.0	0.0	5.3
Dividends declared on common stock	(154.8)	0.0	0.0	(154.8)	0.0
Issuance of common stock	7.2	0.0	7.2	0.0	0.0
Stock-based compensation	9.4	0.0	9.4	0.0	0.0
Balance at Sep. 30, 2015	$ 3,353.4	$ 2.0	$ 1,102.2	$ 2,285.3	$ (36.1)

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Short-Term Debt and Credit Facilities (Tables)

9 Months Ended

Sep. 30, 2015

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The following table provides information regarding the Company's revolving credit agreements at September 30, 2015.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	—	—	%	(D)	December 13, 2018
OG&E (C)	400.0		1.9		0.95	%	(D)	December 13, 2018
Total	$	1,150.0	$	1.9	0.95	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2015.

(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.  

(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.

(D) 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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Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended					9 Months Ended
	Apr. 30, 2014	Sep. 30, 2015		Jun. 30, 2015	Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014		Apr. 16, 2014	May. 01, 2013
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.31800		$ 0.31600
Threshold for Per Unit Incentive Distributions		$ 0.330625					$ 0.330625
Incentive Distribution Percentage Level							50.00%
Equity in earnings of unconsolidated affiliates		$ (71.9)	[1]		$ 44.7	[1]	$ (12.0)	[2]	$ 131.9	[2]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		800.0					800.0
Enogex LLC [Member]
Percentage of Enogex LLC Contributed												100.00%
Increase in fair value of net assets		2,200.0					2,200.0
Enable Midstream Partners [Member]
Goodwill, Impairment Loss		1,086.4					1,086.4
Partners' Capital Account, Units, Sold in Public Offering	25,000,000
Distributions from unconsolidated affiliates		$ 35.1			$ 33.6		$ 104.0		$ 110.1
CenterPoint [Member]
Percent of Subordinated Limited Partner Units											61.40%
OGE Holdings [Member]
Percent of Subordinated Limited Partner Units											61.40%
Common Units Held by Limited Partners of the LLC or LP.							42,832,291
Subordinated Units Held by Limited Partners of the LLC or LP.							68,150,514
Percent of Incentive Distribution Rights		60.00%					60.00%
OGE Energy [Member]
Goodwill, Impairment Loss		$ 108.4					$ 108.4
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest							26.30%

[1] The Company recorded a $108.4 million pre-tax charge during the three months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

[2] The Company recorded a $108.4 million pre-tax charge during the nine months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

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Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost (net of unconsolidated affiliates)		$ 19.7		$ 3.3		$ 26.1		$ 9.5
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		4.2		3.9		12.1		11.5
Interest cost		6.6		7.0		19.6		21.1
Expected return on plan assets		(11.0)		(11.3)		(34.5)		(34.0)
Amortization of net loss		3.8		3.6		13.5		10.7
Amortization of unrecognized prior service cost	[1]	0.1		0.4		0.3		1.3
Settlement		16.2		0.0		16.2		0.0
Total net periodic benefit cost		19.9		3.6		27.2		10.6
Less: Amount paid by unconsolidated affiliates		1.0		0.9		3.1		2.6
Net periodic benefit cost (net of unconsolidated affiliates)		18.9	[2]	2.7	[2]	24.1	[3]	8.0	[3]
Capitalized Portion of Net Periodic Benefit Cost		2.6		0.9		4.6		2.6
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		0.4		0.3		1.0		0.8
Interest cost		0.2		0.2		0.5		0.5
Expected return on plan assets		0.0		0.0		0.0		0.0
Amortization of net loss		0.2		0.1		0.5		0.2
Amortization of unrecognized prior service cost	[1]	0.0		0.0		0.1		0.1
Settlement		0.0		0.0		0.0		0.0
Total net periodic benefit cost		0.8		0.6		2.1		1.6
Less: Amount paid by unconsolidated affiliates		0.0		0.0		0.1		0.1
Net periodic benefit cost (net of unconsolidated affiliates)		0.8	[2]	0.6	[2]	2.0	[3]	1.5	[3]
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		0.4		0.7		1.2		2.3
Interest cost		2.6		2.8		7.7		8.5
Expected return on plan assets		(0.6)		(0.6)		(1.8)		(1.8)
Amortization of net loss		3.5		3.1		10.4		9.3
Amortization of unrecognized prior service cost	[1]	(4.1)		(4.1)		(12.4)		(12.4)
Total net periodic benefit cost		1.8		1.9		5.1		5.9
Less: Amount paid by unconsolidated affiliates		0.4		0.3		1.0		1.0
Net periodic benefit cost (net of unconsolidated affiliates)		1.4	[4]	1.6	[4]	4.1	[5]	4.9	[5]
Capitalized Portion of Net Periodic Benefit Cost		0.5		0.5		1.4		1.5
OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements		2.7		2.8		8.0		8.4
OKLAHOMA | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Settlement		7.4				7.4
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements		1.4		$ 1.3		4.3		$ 3.9
ARKANSAS | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Settlement		$ 1.4				$ 1.4

[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 $19.7 million and $3.3 million of net periodic benefit cost recognized during the three months ended September 30, 2015 and 2014, respectively, OG&E recognized the following:•an increase in pension expense during the three months ended September 30, 2015 and 2014 of $2.7 million and $2.8 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1);

[3] In addition to the $26.1 million and $9.5 million of net periodic benefit cost recognized during the nine months ended September 30, 2015 and 2014, respectively, OG&E recognized the following: •an increase in pension expense during the nine months ended September 30, 2015 and 2014 of $8.0 million and $8.4 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1);

[4] In addition to the $1.4 million and $1.6 million of net periodic benefit cost recognized during the three months ended September 30, 2015 and 2014, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended September 30, 2015 and 2014 of $1.4 million and $1.3 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1).

[5] In addition to the $4.1 million and $4.9 million of net periodic benefit cost recognized during the nine months ended September 30, 2015 and 2014, respectively, OG&E recognized an increase in postretirement medical expense during the nine months ended September 30, 2015 and 2014 of $4.3 million and $3.9 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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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015		Sep. 30, 2014
OPERATING REVENUES	$ 719.8		$ 754.7		$ 1,749.8		$ 1,926.9
COST OF SALES	259.8		305.3		682.3		869.6
OPERATING EXPENSES
Other operation and maintenance	109.4		108.1		334.3		331.9
Depreciation and amortization	77.9		71.7		230.0		207.2
Taxes other than income	21.9		21.5		68.8		66.5
Total operating expenses	209.2		201.3		633.1		605.6
OPERATING INCOME	250.8		248.1		434.4		451.7
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	(71.9)	[1]	44.7	[1]	(12.0)	[2]	131.9	[2]
Allowance for equity funds used during construction	2.2		1.1		5.4		3.0
Other income	8.9		7.2		19.4		11.7
Other expense	(5.3)		(5.8)		(8.5)		(11.2)
Net other income	(66.1)		47.2		4.3		135.4
INTEREST EXPENSE
Interest on long-term debt	37.0		36.3		110.9		109.2
Allowance for borrowed funds used during construction	(1.1)		(0.6)		(2.7)		(1.7)
Interest on short-term debt and other interest charges	1.1		1.5		4.2		5.0
Interest expense	37.0		37.2		112.4		112.5
INCOME BEFORE TAXES	147.7		258.1		326.3		474.6
INCOME TAX EXPENSE	36.5		70.8		84.4		137.2
NET INCOME	$ 111.2		$ 187.3		$ 241.9		$ 337.4
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7		199.3		199.6		199.1
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.7		200.2		199.6		199.9
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.55		$ 0.94		$ 1.21		$ 1.69
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.55		0.94		1.21		1.69
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.27500		$ 0.25000		$ 0.77500		$ 0.70000

[1] The Company recorded a $108.4 million pre-tax charge during the three months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

[2] The Company recorded a $108.4 million pre-tax charge during the nine months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

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Fair Value Measurements, Fair Value Hierarchy (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0.0	$ 0.0

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 43.3	$ 5.5
Accounts receivable, less reserve of $1.5 and $1.6, respectively	222.6	188.8
Accounts receivable - unconsolidated affiliates	5.1	5.6
Accrued unbilled revenues	77.9	55.5
Income taxes receivable	18.4	16.0
Fuel inventories	86.2	58.5
Materials and supplies, at average cost	76.7	78.9
Deferred income taxes	176.4	191.4
Fuel clause under recoveries	1.6	68.3
Other	44.9	38.4
Total current assets	753.1	706.9
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,202.2	1,318.2
Other	70.5	70.1
Total other property and investments	1,272.7	1,388.3
PROPERTY, PLANT AND EQUIPMENT
In service	10,198.7	9,983.0
Construction work in progress	230.6	115.9
Total property, plant and equipment	10,429.3	10,098.9
Less accumulated depreciation	3,262.8	3,119.0
Net property, plant and equipment	7,166.5	6,979.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	389.7	410.4
Other	35.8	42.3
Total deferred charges and other assets	425.5	452.7
TOTAL ASSETS	9,617.8	9,527.8
CURRENT LIABILITIES
Short-term debt	0.0	98.0
Accounts payable	125.7	179.1
Dividends payable	54.9	49.9
Customer deposits	76.0	73.7
Accrued taxes	61.4	39.7
Accrued interest	34.1	43.0
Accrued compensation	37.1	38.2
Long-term debt due within one year	110.0	0.0
Fuel clause over recoveries	34.5	0.0
Other	53.1	51.7
Total current liabilities	586.8	573.3
LONG-TERM DEBT	2,645.5	2,755.3
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	311.0	315.5
Deferred income taxes	2,333.5	2,268.3
Regulatory liabilities	277.0	263.0
Other	110.6	108.0
Total deferred credits and other liabilities	3,032.1	2,954.8
Total liabilities	$ 6,264.4	$ 6,283.4
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	$ 1,104.2	$ 1,087.6
Retained earnings	2,285.3	2,198.2
Accumulated other comprehensive loss, net of tax	(36.1)	(41.4)
Total stockholders' equity	3,353.4	3,244.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 9,617.8	$ 9,527.8

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Summary of Significant Accounting Policies Equity Ownership (Details)	Sep. 30, 2015
CenterPoint [Member]
Percentage Share of Management Rights	50.00%
OGE Energy [Member]
Percentage Share of Management Rights	50.00%

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Policy [Policy Text Block]

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments:  (i) electric utility and (ii) natural gas midstream operations. The accounts of OGE Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and has the ability to exercise significant influence.

The electric utility segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operationsare conducted through OG&E andare subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company.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.

The natural gas midstream operations segment currently represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

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

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 atSeptember 30, 2015andDecember 31, 2014, the results of its operations for the three and nine months endedSeptember 30, 2015and2014 and the results of its cash flows for thenine months endedSeptember 30, 2015and2014, 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 thethree and nine months endedSeptember 30, 2015are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2015or 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 2014Form 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 refunded 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.

Equity Method Investments, Policy [Policy Text Block]

Based on the 50/50 management ownership, with neither company having control, OGE Energy accounts for its interest in Enable using the equity method of accounting.

Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, OGE Energy is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. As discussed above, OGE Energy accounts for the investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. OGE Energy's maximum exposure to loss related to Enable is limited to OGE Energy's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at September 30, 2015. The Company evaluates its equity method investment for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment, and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment which are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

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 are as follows:

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

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

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The Company's long-term debt is recorded at the carrying amount.The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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 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 and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

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 and restricted stock units.

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Summary of Significant Accounting Policies, Regulated Operations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2015	Dec. 31, 2014
Schedule of Regulatory Assets and Liabilities [Line Items]
Prior Period Reclassification Adjustment		$ 1.1
Fuel clause under recoveries		1.6	$ 68.3
Fuel clause over recoveries		34.5	0.0
Total Current Regulatory Assets		41.7	98.2
Total Non-Current Regulatory Assets		389.7	410.4
Total Current Regulatory Liabilities		49.2	24.4
Total Non-Current Regulatory Liabilities		277.0	263.0
Crossroads Wind Farm Rider Over Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Current Regulatory Liabilities	[1]	7.2	10.3
Smart Grid rider over recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Current Regulatory Liabilities	[1]	5.3	12.5
Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Current Regulatory Liabilities	[1]	2.2	1.6
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Liabilities		257.1	248.1
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Liabilities		19.9	14.9
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Current Regulatory Assets	[2]	30.3	19.7
Other [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Current Regulatory Assets	[2],[3]	9.8	10.2
Total Non-Current Regulatory Assets	[3]	17.0	15.7
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Assets		241.6	261.1
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Assets		55.7	56.1
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Assets		43.7	43.9
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Assets		16.6	17.5
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Total Non-Current Regulatory Assets		$ 15.1	$ 16.1

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

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

[3] Prior year amount of $1.1 million reclassified from Non-Current Other assets to Current Other assets.

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Investment in Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

Schedule of Related Party Transactions [Table Text Block]

The following table summarizes related party transactions between OG&E and its affiliate, Enable, during thethree and nine months endedSeptember 30, 2015 and 2014.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2015		2014		2015		2014
Operating Revenues:
Electricity to power electric compression assets	$	4.4	$	4.1	$	11.1	$	10.1
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.8	$	26.3	$	26.2
Natural gas storage services	—		0.1		—		4.5
Natural gas purchases	2.5		3.4		7.1		6.9

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 1.6

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Net income	$ 111.2	$ 187.3	$ 241.9	$ 337.4
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.3, $0.3, $1.7 and $0.9, respectively	0.7	0.5	1.9	1.4
Settlement cost, net of tax of $2.4, $0.0, $2.4 and $0.0, respectively	3.8	0.0	3.8	0.0
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.2, $0.1, $0.6 and $0.4, respectively	0.3	0.1	0.9	0.6
Amortization of prior service cost, net of tax of ($0.3), ($0.2), ($0.8) and ($0.8), respectively	(0.4)	(0.4)	(1.3)	(1.3)
Amortization of deferred interest rate swap hedging losses, net of tax of $0.0, $0.0, $0.0 and $0.1, respectively	0.0	0.1	0.0	0.2
Other comprehensive income, net of tax	4.4	0.3	5.3	0.9
Comprehensive income	$ 115.6	$ 187.6	$ 247.2	$ 338.3

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Short-Term Debt and Credit Facilities

9 Months Ended

Sep. 30, 2015

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$98.0 millionatDecember 31, 2014, with no balance at September 30, 2015. The following table provides information regarding the Company's revolving credit agreements at September 30, 2015.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	—	—	%	(D)	December 13, 2018
OG&E (C)	400.0		1.9		0.95	%	(D)	December 13, 2018
Total	$	1,150.0	$	1.9	0.95	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2015.

(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.  

(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.

(D) 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 by itself 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, 2015 and ending December 31, 2016.

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Document and Entity Information Document	9 Months Ended
	Sep. 30, 2015 shares
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	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,702,572

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Retirement Plans and Postretirement Benefit Plans

9 Months Ended

Sep. 30, 2015

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

Pension and Other Postretirement Benefits Disclosure [Text Block]

Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During the first nine months of 2015, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, the Company recorded pension settlement charges of $16.2 million in the third quarter of 2015. The pension settlement charge did not require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charge was an acceleration of costs that otherwise would be recognized as pension expense in future periods. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in the pension tracker in the regulatory assets and liabilities table in Note 1.

The details of net periodic benefit cost, before consideration of capitalized amounts, 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						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)			2015 (B)		2014 (B)		2015 (C)		2014 (C)
Service cost	$	4.2		$	3.9		$	12.1		$	11.5		$	0.4	$	0.3	$	1.0	$	0.8
Interest cost	6.6			7.0			19.6			21.1			0.2		0.2		0.5		0.5
Expected return on plan assets	(11.0		)	(11.3		)	(34.5		)	(34.0		)	—		—		—		—
Amortization of net loss	3.8			3.6			13.5			10.7			0.2		0.1		0.5		0.2
Amortization of unrecognized prior service cost (A)	0.1			0.4			0.3			1.3			—		—		0.1		0.1
Settlement	16.2			—			16.2			—			—		—		—		—
Total net periodic benefit cost	19.9			3.6			27.2			10.6			0.8		0.6		2.1		1.6
Less: Amount paid by unconsolidated affiliates	1.0			0.9			3.1			2.6			—		—		0.1		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	18.9		$	2.7		$	24.1		$	8.0		$	0.8	$	0.6	$	2.0	$	1.5

(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$19.7 millionand$3.3 millionof net periodic benefit cost recognizedduring thethree months endedSeptember 30, 2015and2014, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedSeptember 30, 2015and2014of$2.7 millionand$2.8 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thethree months endedSeptember 30, 2015 of $7.4 millionrelated tothe pension settlement charge of$16.2 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thethree months endedSeptember 30, 2015 of $1.4 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$16.2 million.

(C) In addition to the$26.1 millionand$9.5 millionof net periodic benefit cost recognizedduring thenine months endedSeptember 30, 2015and2014, respectively, OG&E recognized the following:

• an increase in pension expense during thenine months endedSeptember 30, 2015and2014of$8.0 millionand$8.4 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);

• a deferral of pension expense during thenine months endedSeptember 30, 2015 of $7.4 millionrelated tothe pension settlement charge of$16.2 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thenine months endedSeptember 30, 2015 of $1.4 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$16.2 million.

	Postretirement Benefit Plans
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)
Service cost	$	0.4		$	0.7		$	1.2		$	2.3
Interest cost	2.6			2.8			7.7			8.5
Expected return on plan assets	(0.6		)	(0.6		)	(1.8		)	(1.8		)
Amortization of net loss	3.5			3.1			10.4			9.3
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)	(12.4		)	(12.4		)
Total net periodic benefit cost	1.8			1.9			5.1			5.9
Less: Amount paid by unconsolidated affiliates	0.4			0.3			1.0			1.0
Net periodic benefit cost (net of unconsolidated affiliates)	$	1.4		$	1.6		$	4.1		$	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$1.4 millionand$1.6 millionof net periodic benefit cost recognizedduring thethree months endedSeptember 30, 2015and2014, respectively, OG&E recognized an increase in postretirement medical expense duringthethree months endedSeptember 30, 2015and2014of$1.4 millionand$1.3 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the pension tracker regulatory liability (see Note 1).

(C) In addition to the$4.1 millionand$4.9 millionof net periodic benefit cost recognizedduring thenine months endedSeptember 30, 2015and2014, respectively, OG&E recognized an increase in postretirement medical expense duringthenine months endedSeptember 30, 2015and2014of$4.3 millionand$3.9 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).

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2015		2014		2015		2014
Capitalized portion of net periodic pension benefit cost	$	2.6	$	0.9	$	4.6	$	2.6
Capitalized portion of net periodic postretirement benefit cost	0.5		0.5		1.4		1.5

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.3	$ 0.3	$ 1.7	$ 0.9
Settlement cost	2.4	0.0	2.4	0.0
Postretirement Benefit Plans:
Amortization of deferred net loss	0.2	0.1	0.6	0.4
Amortization of prior service cost	(0.3)	(0.2)	(0.8)	(0.8)
Amortization of deferred interest rate swap hedging losses	$ 0.0	$ 0.0	$ 0.0	$ 0.1

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Fair Value Measurements

9 Months Ended

Sep. 30, 2015

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 are as follows:

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

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

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The Company had nofinancial instruments measured at fair value on a recurring basis atSeptember 30, 2015 and December 31, 2014.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2015 and December 31, 2014.

	September 30, 2015				December 31, 2014
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,510.0	$	2,800.5	$	2,509.7	$	2,957.7
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.1		9.3		10.2		10.3
OGE Energy Senior Notes	100.0		99.9		100.0		99.9

The Company's long-term debt is recorded at the carrying amount.The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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Investment in Unconsolidated Affiliates

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Investment in Unconsolidated Affiliate and Related Party Transactions

On March 14, 2013, OGE Energy entered into a Master Formation Agreement with the ArcLight group and CenterPoint Energy, Inc., pursuant to which OGE Energy, the ArcLight Group and CenterPoint Energy, Inc., agreed to form Enable to own and operate the midstream businesses of OGE Energy and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.

Pursuant to the Master Formation Agreement, OGE Energy and the ArcLight group indirectly contributed100 percentof the equity interests inEnogex LLCto Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost.

On April 16, 2014, Enable completed an initial public offering of 25,000,000 common units resulting in Enable becoming a publicly traded Master Limited Partnership. In connection with Enable’s initial public offering, approximately 61.4 percent of OGE Holdings and CenterPoint’s common units were converted into subordinated units. As a result, following the initial public offering, OGE Holdings owned 42,832,291 common units and 68,150,514 subordinated units of Enable. Holders of subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordinated units will convert into common units when Enable has paid at least the minimum quarterly distribution for three years or paid at least 150 percent of the minimum quarterly distribution for one year.

On July 22, 2015, Enable announced a quarterly dividend distribution of $0.31600per unit on its outstanding common and subordinated units, representing an increase of approximately 1.1 percent over the prior quarter distribution. Enable's gross margins are affected by commodity price movements. Based on forward commodity prices, Enable expects to see a decrease in producer activity that will affect its future distribution growth rate. If cash distributions to Enable’s unitholders exceed $0.330625per unit in any quarter, the general partner will receive increasing percentages, up to50 percent, of the cash Enable distributes in excess of that amount. OGE Holdings is entitled to60 percentof those “incentive distributions.” In certain circumstances, the general partner will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

On October 22, 2015, Enable announced a quarterly dividend distribution of$0.31800per unit on its outstanding common and subordinated units, representing an increase of approximately 0.6 percent over the prior quarter distribution. Distributions received from Enable were $35.1 million and $33.6 million for the three months endedSeptember 30, 2015 and 2014, respectively, and $104.0 million and $110.1 million for the nine months endedSeptember 30, 2015 and 2014, respectively.

At September 30, 2015, OGE Energy held 26.3 percent of the limited partner interests in Enable.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below. Prior to May 1, 2013, operating costs charged and related party transactions between the Company and Enogex Holdings were eliminated in consolidation. OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013.

On May 1, 2013, OGE Energy and Enable entered into a Services Agreement, Employee Transition Agreement, and other agreements whereby OGE Energy agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. The support services automatically extend year-to-year at the end of the initial term, unless terminated by Enable with at least 90 days’ notice. Enable may terminate the initial support services at any time with 180 days' notice if approved by the board of Enable's general partner. Under these agreements, OGE Energy charged operating costs to Enable of $2.6 million and $3.3 million (which results in a corresponding reduction to OGE Energy's operations and maintenance expense) for the three months endedSeptember 30, 2015 and 2014, respectively, and $7.9 million and $13.1 million for the nine months endedSeptember 30, 2015 and 2014, respectively. OGE Energy charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as such.  Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

Additionally, OGE Energy agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, CenterPoint, OGE Energy and Enable agreed to continue the secondment to Enable of 192 OGE Energy employees that participate in OGE Energy's defined benefit and retirement plans beyond December 31, 2014. OGE Energy billed Enable for reimbursement of $7.0 million and $25.0 million during the three months endedSeptember 30, 2015 and September 30, 2014, respectively, and $25.1 million and $78.0 million during the nine months endedSeptember 30, 2015 and September 30, 2014, respectively, under the Transitional Seconding Agreement for employment costs.

OGE Energy had accounts receivable from Enable of $5.1 million and $5.6 million as of September 30, 2015 and December 31, 2014, respectively, for amounts billed for transitional services, including the cost of seconded employees.

Related Party Transactions with Enable

OG&E entered into a new contract with Enable to provide transportation services effective May 1, 2014 which eliminated the natural gas storage services. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries.The following table summarizes related party transactions between OG&E and its affiliate, Enable, during thethree and nine months endedSeptember 30, 2015 and 2014.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2015		2014		2015		2014
Operating Revenues:
Electricity to power electric compression assets	$	4.4	$	4.1	$	11.1	$	10.1
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.8	$	26.3	$	26.2
Natural gas storage services	—		0.1		—		4.5
Natural gas purchases	2.5		3.4		7.1		6.9

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2015 and December 31, 2014 and for the three and nine months endedSeptember 30, 2015 and 2014.

Balance Sheet	September 30, 2015		December 31, 2014
	(In millions)
Current assets	$	427	$	438
Non-current assets	10,774		11,399
Current liabilities	804		671
Non-current liabilities	2,786		2,344

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Income Statement	2015			2014		2015			2014
	(In millions)
Operating revenues	$	646		$	803	$	1,852		$	2,632
Cost of sales	287			439		856			1,550
Operating income	(975		)	152		(778		)	452
Net income	(985		)	139		(817		)	408

The formation of Enable was considered a business combination, and CenterPoint Midstream was the acquirer of Enogex Holdings for accounting purposes.  Under this method, the fair value of the consideration paid by CenterPoint Midstream for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value.  Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to equity of $2.2 billion. Due to the contribution of Enogex LLC to Enable, meeting the requirements of being in substance real estate and thus recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

OGE Energy recorded a loss in equity in earnings of unconsolidated affiliates of $71.9 million and $12.0 million for the three and nine months endedSeptember 30, 2015 and an increase in equity in earnings of unconsolidated affiliates of $44.7 million and $131.9 million for the three and nine months endedSeptember 30, 2014. Equity in earnings of unconsolidated affiliates includes OGE Energy'sshare of Enable's earnings adjusted for the amortization of the basis difference of OGE Energy's original investment in Enogex and its underlying equity in net assets of Enable. The basis difference is the result of the initial contribution of Enogex to Enable in May 2013, and subsequent issuances of equity by Enable, including the IPO in April 2014 and the issuance of common units for the acquisition of CenterPoint's 24.95 percent interest in SESH. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed.Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above.

The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was$0.8 billion as of September 30, 2015.

The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for thethree and nine months endedSeptember 30, 2015 and 2014.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2015			2014		2015			2014
(In millions)
OGE's share of Enable Net Income (Loss)	$	(80.3	)	$	36.4	$	(35.9	)	$	111.1
Amortization of basis difference	3.5			3.4		10.6			10.4
Elimination of Enogex Holdings fair value and other adjustments	4.9			4.9		13.3			10.4
OGE's Equity in earnings of unconsolidated affiliates	$	(71.9	)	$	44.7	$	(12.0	)	$	131.9

Enable tests its goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate that the carrying value of goodwill may not be recoverable. Goodwill is assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. Subsequent to the completion of the October 1, 2014 annual test and previous interim assessment as of December 31, 2014, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which Enable operates. Based on the decline in producer activity and the forecasted impact on future periods, in addition to an increase in the weighted average cost of capital, Enable determined that the impact on its forecasted operating profits and cash flows for its gathering and processing and transportation and storage segments for the next five years would be significantly reduced. As a result, when Enable performed the first step of its annual goodwill impairment analysis as of October 1, 2015, it determined that the carrying value of the gathering and processing and transportation and storage segments exceeded fair value. Enable completed the second step of the goodwill impairment analysis comparing the implied fair value for those reporting units to the carrying amount of that goodwill and determined that goodwill for those units was completely impaired in the amount of $1,086.4 millionas ofSeptember 30, 2015.

Accordingly, theCompany recorded a$108.4 millionpre-tax charge in thethree and nine months endedSeptember 30, 2015for its share of the goodwill impairment, as adjusted for the basis differences.

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2015

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)	September 30, 2015		December 31, 2014
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	30.3	$	19.7
Fuel clause under recoveries	1.6		68.3
Other (A)(C)	9.8		10.2
Total Current Regulatory Assets	$	41.7	$	98.2
Non-Current
Benefit obligations regulatory asset	$	241.6	$	261.1
Income taxes recoverable from customers, net	55.7		56.1
Smart Grid	43.7		43.9
Deferred storm expenses	16.6		17.5
Unamortized loss on reacquired debt	15.1		16.1
Other (C)	17.0		15.7
Total Non-Current Regulatory Assets	$	389.7	$	410.4
Regulatory Liabilities
Current
Crossroads wind farm rider over recovery (B)	$	7.2	$	10.3
Smart Grid rider over recovery (B)	5.3		12.5
Fuel clause over recoveries	34.5		—
Other (B)	2.2		1.6
Total Current Regulatory Liabilities	$	49.2	$	24.4
Non-Current
Accrued removal obligations, net	$	257.1	$	248.1
Pension tracker	19.9		14.9
Total Non-Current Regulatory Liabilities	$	277.0	$	263.0

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

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

(C) Prior year amount of$1.1 millionreclassified from Non-Current Other assets to Current Other assets.

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

The following table summarizes changes to the Company's asset retirement obligations during thenine months endedSeptember 30, 2015and2014.

	Nine Months Ended September 30,
(In millions)	2015			2014
Balance at January 1	$	58.6		$	55.2
Liabilities settled (A)	(0.4		)	(0.2		)
Accretion expense	1.9			1.9
Revisions in estimated cash flows (B)	1.6			1.7
Balance at September 30	$	61.7		$	58.6

(A) In 2015, asset retirement obligations were settled for the asbestos abatement at one of OG&E's generating facilities.

(B) Assumptions changed related to the estimated cost of removal for one of OG&E's generating facilities.

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

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the nine months endedSeptember 30, 2015. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan							Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Settlement cost		Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1	$	—	$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9			—		3.8		0.9			(1.3		)	5.3
Net current period other comprehensive income (loss)	1.9			—		3.8		0.9			(1.3		)	5.3
Balance at September 30, 2015	$	(34.9	)	$	0.1	$	3.8	$	(7.1	)	$	2.0		$	(36.1	)

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 income (loss) by the respective line items in net income during the three and nine months endedSeptember 30, 2015 and 2014.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2015			2014			2015			2014
Losses on cash flow hedges
Interest rate swap	$	—		$	(0.1	)	$	—		$	(0.3	)	Interest expense
	—			(0.1		)	—			(0.3		)	Total before tax
	—			—			—			(0.1		)	Tax benefit
	$	—		$	(0.1	)	$	—		$	(0.2	)	Net of tax
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.0	)	$	(0.8	)	$	(3.6	)	$	(2.3	)	(A)
Settlement cost	(6.2		)	—			(6.2		)	—			(A)
	(7.2		)	(0.8		)	(9.8		)	(2.3		)	Total before tax
	(2.7		)	(0.3		)	(4.1		)	(0.9		)	Tax benefit
	$	(4.5	)	$	(0.5	)	$	(5.7	)	$	(1.4	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	(0.5	)	$	(0.2	)	$	(1.5	)	$	(1.0	)	(A)
Prior service credit	0.7			0.6			2.1			2.1			(A)
	0.2			0.4			0.6			1.1			Total before tax
	0.1			0.1			0.2			0.4			Tax (benefit) expense
	$	0.1		$	0.3		$	0.4		$	0.7		Net of tax
Total reclassifications for the period	$	(4.4	)	$	(0.3	)	$	(5.3	)	$	(0.9	)	Net of tax

(A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

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Report of Business Segments

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Report of Business Segments

Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy, and (ii) the natural gas midstream operations segment. 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.

The following tables summarize the results of the Company's business segments during the three and nine months endedSeptember 30, 2015 and 2014.

Three Months Ended September 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	719.8	$	—		$	—		$	—		$	719.8
Cost of sales	259.8		—			—			—			259.8
Other operation and maintenance	107.4		4.9			(2.9		)	—			109.4
Depreciation and amortization	75.9		—			2.0			—			77.9
Taxes other than income	21.0		—			0.9			—			21.9
Operating income (loss)	255.7		(4.9		)	—			—			250.8
Equity in earnings of unconsolidated affiliates (A)	—		(71.9		)	—			—			(71.9		)
Other income (expense)	6.6		—			(0.7		)	(0.1		)	5.8
Interest expense	36.4		—			0.7			(0.1		)	37.0
Income tax expense	63.0		(26.8		)	0.3			—			36.5
Net income (loss)	$	162.9	$	(50.0	)	$	(1.7	)	$	—		$	111.2
Investment in unconsolidated affiliates	$	—	$	1,202.2		$	—		$	—		$	1,202.2
Total assets	$	8,570.7	$	1,541.5		$	134.0		$	(628.4	)	$	9,617.8

Three Months Ended September 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	754.7	$	—		$	—		$	—		$	754.7
Cost of sales	305.3		—			—			—			305.3
Other operation and maintenance	111.0		0.3			(3.2		)	—			108.1
Depreciation and amortization	69.4		—			2.3			—			71.7
Taxes other than income	20.6		—			0.9			—			21.5
Operating income (loss)	248.4		(0.3		)	—			—			248.1
Equity in earnings of unconsolidated affiliates (A)	—		44.7			—			—			44.7
Other income (expense)	2.9		—			(0.3		)	(0.1		)	2.5
Interest expense	35.3		—			2.0			(0.1		)	37.2
Income tax expense	58.7		16.2			(4.1		)	—			70.8
Net income (loss)	$	157.3	$	28.2		$	1.8		$	—		$	187.3
Investment in unconsolidated affiliates	$	—	$	1,311.1		$	—		$	—		$	1,311.1
Total assets	$	8,003.1	$	1,427.2		$	204.1		$	(171.7	)	$	9,462.7

(A) The Company recorded a $108.4 million pre-tax charge during the three months endedSeptember 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

Nine Months Ended September 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,749.8	$	—		$	—		$	—		$	1,749.8
Cost of sales	682.3		—			—			—			682.3
Other operation and maintenance	337.3		5.9			(8.9		)	—			334.3
Depreciation and amortization	224.0		—			6.0			—			230.0
Taxes other than income	65.7		—			3.1			—			68.8
Operating income (loss)	440.5		(5.9		)	(0.2		)	—			434.4
Equity in earnings of unconsolidated affiliates (A)	—		(12.0		)	—			—			(12.0		)
Other income (expense)	13.9		—			2.6			(0.2		)	16.3
Interest expense	110.5		—			2.1			(0.2		)	112.4
Income tax expense	94.9		(8.7		)	(1.8		)	—			84.4
Net income (loss)	$	249.0	$	(9.2	)	$	2.1		$	—		$	241.9
Investment in unconsolidated affiliates	$	—	$	1,202.2		$	—		$	—		$	1,202.2
Total assets	$	8,570.7	$	1,541.5		$	134.0		$	(628.4	)	$	9,617.8

Nine Months Ended September 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,926.9	$	—		$	—		$	—		$	1,926.9
Cost of sales	869.6		—			—			—			869.6
Other operation and maintenance	343.1		0.7			(11.9		)	—			331.9
Depreciation and amortization	198.7		—			8.5			—			207.2
Taxes other than income	63.1		—			3.4			—			66.5
Operating income (loss)	452.4		(0.7		)	—			—			451.7
Equity in earnings of unconsolidated affiliates (A)	—		131.9			—			—			131.9
Other income (expense)	4.5		—			(0.8		)	(0.2		)	3.5
Interest expense	106.7		—			6.0			(0.2		)	112.5
Income tax expense	95.3		49.6			(7.7		)	—			137.2
Net income (loss)	$	254.9	$	81.6		$	0.9		$	—		$	337.4
Investment in unconsolidated affiliates	$	—	$	1,311.1		$	—		$	—		$	1,311.1
Total assets	$	8,003.1	$	1,427.2		$	204.1		$	(171.7	)	$	9,462.7

(A) The Company recorded a $108.4 million pre-tax charge during the nine months endedSeptember 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

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Common Equity

9 Months Ended

Sep. 30, 2015

Common Equity [Text Block]

Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 16,498 shares and 217,370 shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months endedSeptember 30, 2015 and received proceeds of $0.5 million and $7.2 million, respectively.  The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital requirements or working capital needs.  At September 30, 2015, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions except per share data)	2015		2014		2015		2014
Net Income	$	111.2	$	187.3	$	241.9	$	337.4
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.3		199.6		199.1
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—		0.9		—		0.8
Diluted average common shares outstanding	199.7		200.2		199.6		199.9
Basic Earnings Per Average Common Share	$	0.55	$	0.94	$	1.21	$	1.69
Diluted Earnings Per Average Common Share	$	0.55	$	0.94	$	1.21	$	1.69
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2015

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 thethree and nine months endedSeptember 30, 2015 and 2014related to the Company's performance units and restricted stock.

	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2015			2014		2015		2014
Performance units
Total shareholder return	$	1.9		$	2.0	$	5.7	$	5.9
Earnings per share	(0.8		)	0.1		0.3		2.2
Total performance units	1.1			2.1		6.0		8.1
Restricted stock	—			—		0.1		0.1
Total compensation expense	1.1			2.1		6.1		8.2
Less: Amount paid by unconsolidated affiliates	(0.2		)	0.6		0.3		2.5
Net compensation expense	$	1.3		$	1.5	$	5.8	$	5.7
Income tax benefit	$	0.5		$	0.6	$	2.3	$	2.2

The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units. During the three and nine months endedSeptember 30, 2015, there were 912 shares and 81,865shares, respectively, of new common stock issued pursuant to the Company's stock incentive plans related to restricted stock grants (net of forfeitures) and payouts of earned performance units. During thethree and nine months endedSeptember 30, 2015, there wereno shares and 1,070 shares, respectively, of restricted stock returned to the Company to satisfy tax liabilities.

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Income Taxes

9 Months Ended

Sep. 30, 2015

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 to2012or state and local tax examinations by tax authorities for years prior to2011.  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 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 and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

As previously reported, OG&E has determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During the third quarter of 2015, OG&E recorded an additional reserve for this item of$3.8 million ($2.4 millionafter the federal tax benefit) related to Oklahoma investment tax credits generated in the current year 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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Long-Term Debt

9 Months Ended

Sep. 30, 2015

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

AtSeptember 30, 2015, 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)
0.05%	-	0.13%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.06%	-	0.19%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.14%	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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Report of Business Segments (Tables)

9 Months Ended

Sep. 30, 2015

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 three and nine months endedSeptember 30, 2015 and 2014.

Three Months Ended September 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	719.8	$	—		$	—		$	—		$	719.8
Cost of sales	259.8		—			—			—			259.8
Other operation and maintenance	107.4		4.9			(2.9		)	—			109.4
Depreciation and amortization	75.9		—			2.0			—			77.9
Taxes other than income	21.0		—			0.9			—			21.9
Operating income (loss)	255.7		(4.9		)	—			—			250.8
Equity in earnings of unconsolidated affiliates (A)	—		(71.9		)	—			—			(71.9		)
Other income (expense)	6.6		—			(0.7		)	(0.1		)	5.8
Interest expense	36.4		—			0.7			(0.1		)	37.0
Income tax expense	63.0		(26.8		)	0.3			—			36.5
Net income (loss)	$	162.9	$	(50.0	)	$	(1.7	)	$	—		$	111.2
Investment in unconsolidated affiliates	$	—	$	1,202.2		$	—		$	—		$	1,202.2
Total assets	$	8,570.7	$	1,541.5		$	134.0		$	(628.4	)	$	9,617.8

Three Months Ended September 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	754.7	$	—		$	—		$	—		$	754.7
Cost of sales	305.3		—			—			—			305.3
Other operation and maintenance	111.0		0.3			(3.2		)	—			108.1
Depreciation and amortization	69.4		—			2.3			—			71.7
Taxes other than income	20.6		—			0.9			—			21.5
Operating income (loss)	248.4		(0.3		)	—			—			248.1
Equity in earnings of unconsolidated affiliates (A)	—		44.7			—			—			44.7
Other income (expense)	2.9		—			(0.3		)	(0.1		)	2.5
Interest expense	35.3		—			2.0			(0.1		)	37.2
Income tax expense	58.7		16.2			(4.1		)	—			70.8
Net income (loss)	$	157.3	$	28.2		$	1.8		$	—		$	187.3
Investment in unconsolidated affiliates	$	—	$	1,311.1		$	—		$	—		$	1,311.1
Total assets	$	8,003.1	$	1,427.2		$	204.1		$	(171.7	)	$	9,462.7

(A) The Company recorded a $108.4 million pre-tax charge during the three months endedSeptember 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 for further discussion of Enable's goodwill impairment.

Nine Months Ended September 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,749.8	$	—		$	—		$	—		$	1,749.8
Cost of sales	682.3		—			—			—			682.3
Other operation and maintenance	337.3		5.9			(8.9		)	—			334.3
Depreciation and amortization	224.0		—			6.0			—			230.0
Taxes other than income	65.7		—			3.1			—			68.8
Operating income (loss)	440.5		(5.9		)	(0.2		)	—			434.4
Equity in earnings of unconsolidated affiliates (A)	—		(12.0		)	—			—			(12.0		)
Other income (expense)	13.9		—			2.6			(0.2		)	16.3
Interest expense	110.5		—			2.1			(0.2		)	112.4
Income tax expense	94.9		(8.7		)	(1.8		)	—			84.4
Net income (loss)	$	249.0	$	(9.2	)	$	2.1		$	—		$	241.9
Investment in unconsolidated affiliates	$	—	$	1,202.2		$	—		$	—		$	1,202.2
Total assets	$	8,570.7	$	1,541.5		$	134.0		$	(628.4	)	$	9,617.8

Nine Months Ended September 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,926.9	$	—		$	—		$	—		$	1,926.9
Cost of sales	869.6		—			—			—			869.6
Other operation and maintenance	343.1		0.7			(11.9		)	—			331.9
Depreciation and amortization	198.7		—			8.5			—			207.2
Taxes other than income	63.1		—			3.4			—			66.5
Operating income (loss)	452.4		(0.7		)	—			—			451.7
Equity in earnings of unconsolidated affiliates (A)	—		131.9			—			—			131.9
Other income (expense)	4.5		—			(0.8		)	(0.2		)	3.5
Interest expense	106.7		—			6.0			(0.2		)	112.5
Income tax expense	95.3		49.6			(7.7		)	—			137.2
Net income (loss)	$	254.9	$	81.6		$	0.9		$	—		$	337.4
Investment in unconsolidated affiliates	$	—	$	1,311.1		$	—		$	—		$	1,311.1
Total assets	$	8,003.1	$	1,427.2		$	204.1		$	(171.7	)	$	9,462.7

(A) The Company recorded a $108.4 million pre-tax charge during the nine months endedSeptember 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

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Long-Term Debt (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($)
Debt Instrument [Line Items]
Percent of Principal Amount Subject to Optional Tender	100.00%
Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	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	0.05%
Series Maximum	0.13%
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Series Minimum	0.06%
Series Maximum	0.19%
Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Series Minimum	0.05%
Series Maximum	0.14%
OG&E [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Long term debt	$ 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	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	$ 56.0

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Rate Matters and Regulation

9 Months Ended

Sep. 30, 2015

Regulated Operations [Abstract]

Rate Matters and Regulation

Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note15to the Company's Consolidated Financial Statements included in the Company's 2014Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Arkansas Regulatory Developments

The State of Arkansas earlier in 2015 enacted two laws related to rate filings. Act 725, among other things, provides a public utility the option, to be exercised concurrently with the filing of a general rate application, to file notice of its intent to exercise its right for an annual formula rate review so as to provide a streamlined review of the utility’s rates to determine if adjustments in rates are justified. If the utility exercises such rights, rates may be adjusted if the earned return rate is 0.5 percent above or below the target return rate. This procedure is expected to reduce regulatory lag in Arkansas. Act 725 additionally allows for evidence to be presented, relative to the calculation of the return on common equity, comparing the requested return on common equity to approved returns on common equity for public utilities delivering similar services with corresponding risks within Arkansas and also in similar regulatory jurisdictions in the same general part of the country.

Act 1000 amends and clarifies existing interim rate requirements to expand the types of expenses that may be recorded and specifically authorize the recovery of allowance for funds used during construction. Act 1000 allows a public utility to file for an interim rate schedule through which it may recover investments and expenses, including allowance for funds used during construction, expended complying with legislative or administrative rules, regulations, or requirements related to the protection of the public, health, safety, or the environment. Rates are implemented at the time of filing of the interim rate schedule, subject to refund. As permitted by Act 1000, on May 8, 2015, OG&E filed an interim rate schedule to recover expenditures for the Arkansas portion of the low NOx burners made in order to comply with the Regional Haze rule for NOx.

Pending Regulatory Matters

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance and Mustang Modernization Plan included in this application to be approximately$1.1 billion. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

As previously reported, on June 8, 2015 the ALJ issued his report on OG&E's application. While the ALJ in his report agrees that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s environmental compliance plan is the best approach, the ALJ makes various recommendations including, among others, that: (i) the OCC should not raise rates at this time; (ii) with respect to OG&E’s environmental compliance plan, the OCC should grant pre-approval of the estimated costs for new equipment as set by contract, including installation costs covered by a contract, but pre-approval of other equipment and installation costs that were still being negotiated at the end of the evidentiary hearing on April 8, 2015 should be deferred and may be considered in the next general rate case; (iii) the foregoing pre-approval is subject to the condition that the OCC should direct OG&E to issue requests for information for at least 200 MWs of wind power within thirty days of a final order; (iv) the OCC should postpone consideration of all other cost recovery issues until the next general rate case; (v) the OCC should direct the PUD Director to commence a general rate case; and (vi) the OCC should deny the Mustang Modernization Plan. OG&E filed exceptions to the ALJ's report in which OG&E set forth the various findings and recommendations that OG&E believes to be erroneous, including the ALJ’s refusal to recommend a recovery rider for OG&E environmental compliance plan and the ALJ’s recommendation that the OCC should deny the Mustang Modernization Plan. The OCC heard oral arguments on June 25, 2015 and took the case under advisement. On July 21, 2015, Commissioner Bob Anthony (one of the three commissioners on the OCC) issued his deliberation statement that was consistent with many parts of the ALJ Report, including the ALJ’s support of OG&E’s environmental compliance plan, the ALJ’s recommendation, as described above, to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other costs recovery issues until the next general rate case. OG&E cannot predict the outcome of this proceeding.

Integrated Resource Plans

In August 2015, OG&E initiated the process to update its IRP pursuant to the OCC rules. After engaging interested stakeholders in August and September, OG&E finalized the 2015 IRP and submitted it to the OCC on October 1, 2015. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the environmental compliance plan and other parts of the action plan contained in the IRP submitted in 2014.

Oklahoma Demand Program Rider Review

In July 2012, OG&E filed an application with the OCC to recover certain costs associated with Demand Programs through the Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off peak hours during the months of May through October, by offering lower rates to those customers in the off peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates.  Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers, by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.

In December 2012, the OCC issued an order approving the recovery of costs associated with the Demand Programs, including the lost revenues associated with the SmartHours program, subject to the Oklahoma PUD staff review.

In March 2014, the Oklahoma PUD staff began their review of the Demand Program cost, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the Oklahoma PUD staff on the methodology to be used to calculate lost revenues associated with the SmartHours program and the amount of lost revenue for 2013, which totaled$10.1 million. The agreement also included utilizing the same methodology for calculating lost revenues for 2014, which resulted in lost revenues for 2014 of$11.6 million.

In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues, in accordance with the agreement that it believed had been reached with the Oklahoma PUD staff.

In April 2015, the Oklahoma PUD staff filed an application, seeking an order from the OCC determining the proper calculation methodology for lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues.  In the application, the Oklahoma PUD staff recommends the OCC approve the Oklahoma PUD staff methodology for calculating lost revenues associated with the SmartHours program, which differs from the methodology that OG&E believes it had agreed upon and which would result in recovery of lost revenue for 2013 of only$4.9 million, a reduction of$5.2 millionfrom the amount recorded by OG&E for 2013.

OG&E believes that the methodology agreed to in November 2014, is consistent with the 2012 OCC order, and believes that it is probable that it will recover the$10.1 millionof lost revenues associated with 2013, the$11.6 millionassociated with 2014 and the $11.1 million associated with year-to-date 2015. A hearing was held on June 30, 2015 and July 1, 2015. OG&E is unable to predict when it will receive a ruling from the OCC.

Fuel Adjustment Clause Review for Calendar Year 2013

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. On May 21, 2015, the ALJ recommended that the OCC find that OG&E's 2013 electric generation, purchased power and fuel procurement processes and costs were prudent, accurate and properly applied to customer billing statements. OG&E received an order to that effect from the OCC on June 17, 2015.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 2, 2015. A hearing is scheduled to be held on April 7, 2016.

Oklahoma Rate Case Filing

On July 28, 2015 OG&E filed a notice of intent with the OCC to file a general rate case on or before November 30, 2015 based on a June 30, 2015 test year and to modify rates no later than 180 days from the date of filing the rate case.  Among the matters OG&E expects the rate case to address are certain cost recovery riders, the retail portion of transmission expenditures made by OG&E since the last rate case, ad valorem taxes, depreciation rates, impact of the expiration of OG&E’s wholesale contracts and the costs associated with the SPP Integrated Market.

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

9 Months Ended

Sep. 30, 2015

Summarized Financial Information of Equity Method Investment [Line Items]

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Income Statement	2015			2014		2015			2014
	(In millions)
Operating revenues	$	646		$	803	$	1,852		$	2,632
Cost of sales	287			439		856			1,550
Operating income	(975		)	152		(778		)	452
Net income	(985		)	139		(817		)	408

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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan		$ 7.2	$ 10.1
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, Dividend Reinvestment Plan and Stock Purchase Plan	16,498	217,370
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan	$ 0.5	$ 7.2
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan	4,774,442	4,774,442

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Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 5.1		$ 5.1		$ 5.6
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Electricity to power electric compression assets	4.4	$ 4.1	11.1	$ 10.1
Operating Costs Charged [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Operating expenses	2.6	3.3	7.9	13.1
Employment Costs [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Operating expenses	7.0	25.0	25.1	78.0
Natural Gas Transportation [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	8.8	8.8	26.3	26.2
Natural Gas Storage [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	0.0	0.1	0.0	4.5
Natural Gas Purchases [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	$ 2.5	$ 3.4	$ 7.1	$ 6.9

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$ 241.9	$ 337.4
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization		230.0	207.2
Deferred income taxes and investment tax credits, net		62.3	142.1
Equity in earnings of unconsolidated affiliates	[1]	12.0	(131.9)
Distributions from unconsolidated affiliates		67.1	110.1
Allowance for equity funds used during construction		(5.4)	(3.0)
Stock-based compensation		3.8	(5.4)
Excess tax benefit on stock-based compensation		(5.2)	0.0
Regulatory assets		12.7	1.6
Regulatory liabilities		(13.9)	(5.6)
Other assets		12.7	(18.8)
Other liabilities		0.1	24.8
Change in certain current assets and liabilities
Accounts receivable, net		(33.8)	(58.8)
Accounts receivable - unconsolidated affiliates		0.5	5.5
Accrued unbilled revenues		(22.4)	(13.3)
Fuel, materials and supplies inventories		(25.5)	33.5
Fuel clause under recoveries		66.7	(58.1)
Other current assets		(8.9)	(6.4)
Accounts payable		(57.7)	(100.7)
Fuel clause over recoveries		34.5	(0.4)
Other current liabilities		37.6	6.7
Net Cash Provided from Operating Activities		609.1	466.5
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)		(375.0)	(437.4)
Return of capital - equity method investments		36.9	9.5
Proceeds from sale of assets		2.2	0.6
Net Cash Used in Investing Activities		(335.9)	(427.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock		(149.7)	(134.3)
Proceeds from long-term debt		0.0	246.5
Issuance of common stock		7.2	10.1
Excess tax benefit on stock-based compensation		5.2	0.0
Payment of long-term debt		(0.1)	(140.1)
Decrease in short-term debt		(98.0)	(28.2)
Net Cash Used in Financing Activities		(235.4)	(46.0)
NET CHANGE IN CASH AND CASH EQUIVALENTS		37.8	(6.8)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		5.5	6.8
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$ 43.3	$ 0.0

[1] The Company recorded a $108.4 million pre-tax charge during the nine months ended September 30, 2015 for its share of Enable's goodwill impairment, as adjusted for the basis differences. See Note 3 of this Form 10-Q for further discussion of Enable's goodwill impairment.

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Accounting Pronouncements

9 Months Ended

Sep. 30, 2015

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

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

Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. For public entities, the deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017.

In April 2015, the FASB issued ASU 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". The amendments in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments. The FASB issued the updated guidance as part of its initiative to reduce complexity in accounting standards, as it had received feedback that having different balance sheet presentation requirements for debt issuance costs and debt discount and premium created unnecessary complexity. On June 18, 2015, the SEC observer stated that given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to revolving debt arrangements, the SEC staff would not object to an entity deferring and presenting such costs as an asset and subsequently amortizing them ratably over the term of the revolving debt arrangement. For public business entities, the amendments in this ASU are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company will reflect the impact of this ASU in the first quarter of 2016.

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Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2015

Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]

Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]

The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for thethree and nine months endedSeptember 30, 2015 and 2014.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2015			2014		2015			2014
(In millions)
OGE's share of Enable Net Income (Loss)	$	(80.3	)	$	36.4	$	(35.9	)	$	111.1
Amortization of basis difference	3.5			3.4		10.6			10.4
Elimination of Enogex Holdings fair value and other adjustments	4.9			4.9		13.3			10.4
OGE's Equity in earnings of unconsolidated affiliates	$	(71.9	)	$	44.7	$	(12.0	)	$	131.9

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (36.1)	$ (41.4)
Amounts reclassified from accumulated other comprehensive income (loss)	5.3
Net current period other comprehensive income (loss)	5.3
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(34.9)	(36.8)
Amounts reclassified from accumulated other comprehensive income (loss)	1.9
Net current period other comprehensive income (loss)	1.9
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(7.1)	(8.0)
Amounts reclassified from accumulated other comprehensive income (loss)	0.9
Net current period other comprehensive income (loss)	0.9
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	0.1	0.1
Amounts reclassified from accumulated other comprehensive income (loss)	0.0
Net current period other comprehensive income (loss)	0.0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	2.0	3.3
Amounts reclassified from accumulated other comprehensive income (loss)	(1.3)
Net current period other comprehensive income (loss)	(1.3)
Settlement Cost [Member] | Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	3.8	$ 0.0
Amounts reclassified from accumulated other comprehensive income (loss)	3.8
Net current period other comprehensive income (loss)	$ 3.8

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2015

Long-term Purchase Commitment [Line Items]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

Except as set forth below, in Note13 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes14and15 to the Company's Consolidated Financial Statements included in the Company's 2014Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Other Purchase Obligation and Contingencies

On June 15, 2015 OG&E entered into a contract with Siemens Energy Inc. for the purchase, design and engineering of seven simple-cycle gas turbine generators for$170.3 millionto be completed byJune 1, 2018.

Environmental Laws and Regulations

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

On July 8, 2013, the U.S. Department of Justice, filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. The Sierra Club intervened in this proceeding. On September 6, 2013, OG&E filed a Motion to Dismiss the case.  On January 15, 2015, U.S. District Judge Timothy DeGuisti dismissed the complaints filed by the EPA and Sierra Club.  The Court held that it lacked subject matter jurisdiction over the Plaintiffs’ claims because Plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution.   The court also ruled in the alternative that, even if the Plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.”  The EPA and the Sierra Club did not file an appeal of the Court’s ruling.

On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008, were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the Eastern District dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the Eastern District to dismiss its remaining claims with prejudice. On August 27, 2014, the Eastern District granted the Sierra Club's request. The Sierra Club has filed a Notice of Appeal with the 10th Circuit where oral argument was held on March 18, 2015.

At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act, and OG&E expects to vigorously defend against the claims that have been asserted. If OG&E does not prevail in the remainder of the proceedings, the Sierra Club could seek to require OG&E to install additional pollution control equipment at Muskogee 6, including scrubbers, baghouses and selective catalytic reduction systemsand pay fines and significant penalties as a result of the allegations. 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. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.

Air Quality Control System

On September 10, 2014,  OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2.  OG&E entered into an agreement on February 9, 2015, to install the scrubber systems.  The scrubbers are part of OG&E’s Environmental Compliance Plan and are scheduled to be completed by 2019. More detail regarding the Environmental Plan can be found under the “Pending Regulatory Matters” in Note 13.

Clean Power Plan

On August 3, 2015, the EPA issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates.  The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan.  The EPA has given states the option to develop compliance plans for annual rate-based reductions (lb/MWh) or mass-based tonnage limits for CO₂.  The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed43 percentreduction to32 percentin the final rule.  The mass-based approach for existing units calls for a24 percentreduction by 2030 in Oklahoma.  The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission.  The compliance period begins in 2022, and emission reductions will be phased in to 2030.  The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan is not submitted to the EPA.  OG&E is currently evaluating the Clean Power Plan rules and is working in collaboration with the State of Oklahoma on OG&E's plans.

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, 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.