OGE Energy (OGE) 10-Q 5 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2015shares
Document Information [Line Items]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	1,021,635
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	2,015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,702,572

CONDENSED CONSOLIDATED STATEMEN

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		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)	[2]	131.9	[2]
Allowance for equity funds used during construction	2.2		1.1		5.4		3
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		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
Interest expense	37		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.

CONDENSED CONSOLIDATED STATEME3

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	3.8	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	0.1	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

CONDENSED CONSOLIDATED STATEME4

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	2.4	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	$ 0.1

CONDENSED CONSOLIDATED STATEME5

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	207.2
Deferred income taxes and investment tax credits, net		62.3	142.1
Equity in earnings of unconsolidated affiliates	[1]	12	(131.9)
Distributions from unconsolidated affiliates		67.1	110.1
Allowance for equity funds used during construction		(5.4)	(3)
Stock-based compensation		3.8	(5.4)
Excess tax benefit on stock-based compensation		(5.2)	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)	(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	246.5
Issuance of common stock		7.2	10.1
Excess tax benefit on stock-based compensation		5.2	0
Payment of long-term debt		(0.1)	(140.1)
Decrease in short-term debt		(98)	(28.2)
Net Cash Used in Financing Activities		(235.4)	(46)
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
[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.

CONDENSED CONSOLIDATED BALANCE

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
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
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
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	98
Accounts payable	125.7	179.1
Dividends payable	54.9	49.9
Customer deposits	76	73.7
Accrued taxes	61.4	39.7
Accrued interest	34.1	43
Accrued compensation	37.1	38.2
Long-term debt due within one year	110	0
Fuel clause over recoveries	34.5	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	315.5
Deferred income taxes	2,333.5	2,268.3
Regulatory liabilities	277	263
Other	110.6	108
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

CONDENSED CONSOLIDATED BALANCE7

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

CONDENSED CONSOLIDATED STATEME8

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	$ 1,071.6	$ 1,991.7	$ (28.2)
Changes in Stockholders' Equity
Net income	337.4	0	0	337.4	0
Other comprehensive income, net of tax	0.9	0	0	0	0.9
Dividends declared on common stock	(139.5)	0	0	(139.5)	0
Issuance of common stock	10.1	0	10.1	0	0
Stock-based compensation	(3)	0	(3)	0	0
Balance at Sep. 30, 2014	3,243	2	1,078.7	2,189.6	(27.3)
Balance at Dec. 31, 2014	3,244.4	2	1,085.6	2,198.2	(41.4)
Changes in Stockholders' Equity
Net income	241.9	0	0	241.9	0
Other comprehensive income, net of tax	5.3	0	0	0	5.3
Dividends declared on common stock	(154.8)	0	0	(154.8)	0
Issuance of common stock	7.2	0	7.2	0	0
Stock-based compensation	9.4	0	9.4	0	0
Balance at Sep. 30, 2015	$ 3,353.4	$ 2	$ 1,102.2	$ 2,285.3	$ (36.1)

Summary of Significant Accounti

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 segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory , 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, 2013 by 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 and the 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 at September 30, 2015 and December 31, 2014 , the results of its operations for the three and nine months ended September 30, 2015 and 2014 and the results of its cash flows for the nine months ended September 30, 2015 and 2014 , have been included and are of a normal recurring nature except as otherwise disclosed. Due to seasonal fluctuations and other factors , the Company's operating results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2014 Form 10-K. Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. 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 the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets. (C) Prior year amount of $1.1 million reclassified 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 the nine months ended September 30, 2015 and 2014 . 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 ended September 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 ended September 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).

Accounting Pronouncements

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.

Investment in Unconsolidated Af

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 contributed 100 percent of the equity interests in Enogex LLC to 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 $0.31600 per 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 $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent , of the cash Enable distributes in excess of that amount. OGE Holdings is entitled to 60 percent of 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 $0.31800 per 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 ended September 30, 2015 and 2014 , respectively, and $104.0 million and $110.1 million for the nine months ended September 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 ended September 30, 2015 and 2014 , respectively, and $7.9 million and $13.1 million for the nine months ended September 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 ended September 30, 2015 and September 30, 2014 , respectively, and $25.1 million and $78.0 million during the nine months ended September 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 the three and nine months ended September 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 ended September 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 ended September 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 ended September 30, 2014 . Equity in earnings of unconsolidated affiliates includes OGE Energy's share 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 the three and nine months ended September 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 million as of September 30, 2015 . Accordingly, the Company recorded a $108.4 million pre-tax charge in the three and nine months ended September 30, 2015 for its share of the goodwill impairment, as adjusted for the basis differences.

Fair Value Measurements

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 no financial instruments measured at fair value on a recurring basis at September 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 Carrying Amount Fair 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.

Stock-Based Compensation

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 the three and nine months ended September 30, 2015 and 2014 related 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 ended September 30, 2015 , there were 912 shares and 81,865 shares , 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 the three and nine months ended September 30, 2015 , there were no shares and 1,070 shares, respectively, of restricted stock returned to the Company to satisfy tax liabilities.

Income Taxes

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 to 2012 or state and local tax examinations by tax authorities for years prior to 2011 . 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 million after 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.

Common Equity

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 ended September 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 — — — —

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2015
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	Long-Term Debt At September 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, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as long-term debt in the Company's Condensed Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

Short-Term Debt and Credit Faci

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 Credit Facilities The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The short-term debt balance was $98.0 million at December 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 downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit. OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.

Retirement Plans and Postretire

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 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 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); • a deferral of pension expense during the three months ended September 30, 2015 of $7.4 million related to the 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 the three months ended September 30, 2015 of $1.4 million related to the Arkansas jurisdictional portion of the pension settlement charge of $16.2 million . (C) 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); • a deferral of pension expense during the nine months ended September 30, 2015 of $7.4 million related to the 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 the nine months ended September 30, 2015 of $1.4 million related to the Arkansas jurisdictional portion of the 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 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). (C) 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). 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

Report of Business Segments

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 ended September 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 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. 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 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.

Commitments and Contingencies

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 Note 13 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 Notes 14 and 15 to the Company's Consolidated Financial Statements included in the Company's 2014 Form 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 million to be completed by June 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 systems and 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 $37,500 per 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 CO 2 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 CO 2 . The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed 43 percent reduction to 32 percent in the final rule. The mass-based approach for existing units calls for a 24 percent reduction 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 Company is 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 Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements. 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.

Rate Matters and Regulation

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 Note 15 to the Company's Consolidated Financial Statements included in the Company's 2014 Form 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 million from 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 million of lost revenues associated with 2013, the $11.6 million associated 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.

Summary of Significant Accoun22

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 segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory , 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, 2013 by 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 and the 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 at September 30, 2015 and December 31, 2014 , the results of its operations for the three and nine months ended September 30, 2015 and 2014 and the results of its cash flows for the nine months ended September 30, 2015 and 2014 , have been included and are of a normal recurring nature except as otherwise disclosed. Due to seasonal fluctuations and other factors , the Company's operating results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2014 Form 10-K.
Public Utilities, Policy [Policy Text Block]	Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or 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.

Summary of Significant Accoun23

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 the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets. (C) Prior year amount of $1.1 million reclassified 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 the nine months ended September 30, 2015 and 2014 . 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 ended September 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 ended September 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).

Investment in Unconsolidated 24

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 the three and nine months ended September 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

Investment in Unconsolidated 25

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 ended September 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

Investment in Unconsolidated 26

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

Investment in Unconsolidated 27

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 the three and nine months ended September 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

Fair Value Measurements (Tables

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 Carrying Amount Fair 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

Stock-Based Compensation (Table

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 the three and nine months ended September 30, 2015 and 2014 related 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

Common Equity (Tables)

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 — — — —

Long-Term Debt (Tables)

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

Short-Term Debt and Credit Fa32

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.

Retirement Plans and Postreti33

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 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 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); • a deferral of pension expense during the three months ended September 30, 2015 of $7.4 million related to the 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 the three months ended September 30, 2015 of $1.4 million related to the Arkansas jurisdictional portion of the pension settlement charge of $16.2 million . (C) 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); • a deferral of pension expense during the nine months ended September 30, 2015 of $7.4 million related to the 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 the nine months ended September 30, 2015 of $1.4 million related to the Arkansas jurisdictional portion of the 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 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). (C) 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).
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

Report of Business Segments (Ta

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 ended September 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 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. 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 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.

Summary of Significant Accoun35

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%

Summary of Significant Accoun36

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
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	263
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	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.

Summary of Significant Accoun37

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.

Summary of Significant Accoun38

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)
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
Net current period other comprehensive income (loss)	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	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
Amounts reclassified from accumulated other comprehensive income (loss)	3.8
Net current period other comprehensive income (loss)	$ 3.8

Summary of Significant Accoun39

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)	(0.8)	(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	(6.2)	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)
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	(0.1)	0	(0.3)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax		0	0	0	(0.1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax		0	(0.1)	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	$ (0.1)	$ 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).

Investment in Unconsolidated 40

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)	[2]	$ 131.9	[2]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		800					800
Enogex LLC [Member]
Percentage of Enogex LLC Contributed												100.00%
Increase in fair value of net assets		2,200					2,200
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		$ 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.

Investment in Unconsolidated 41

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	25	25.1	78
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	0.1	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

Investment in Unconsolidated 42

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	$ 438
Non-current assets	10,774	11,399
Current liabilities	804	671
Non-current liabilities	$ 2,786	$ 2,344

Investment in Unconsolidated 43

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	$ 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

Investment in Unconsolidated 44

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)	[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.

Fair Value Measurements, Fair V

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

Fair Value Measurements Carryin

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	$ 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	100
Long-Term Debt, Fair Value	$ 99.9	$ 99.9

Stock-Based Compensation (Detai

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	8.1
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	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	$ 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

Income Taxes (Details)

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

Common Equity Automatic Dividen

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

Common Equity Earnings Per Shar

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	0.9	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

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
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. 1, 2025
Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 1, 2025
Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 1, 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
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

Short-Term Debt and Credit Fa52

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	$ 98
Line of Credit Facility [Abstract]
Aggregate Commitment		1,150
Amount Outstanding	[1]	$ 1.9
Weighted Average Interest Rate		0.95%
OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[2]	$ 750
Amount Outstanding	[1],[2]	$ 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
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
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.

Retirement Plans and Postreti53

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		19.6		21.1
Expected return on plan assets		(11)		(11.3)		(34.5)		(34)
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		16.2		0
Total net periodic benefit cost		19.9		3.6		27.2		10.6
Less: Amount paid by unconsolidated affiliates		1		0.9		3.1		2.6
Net periodic benefit cost (net of unconsolidated affiliates)		18.9	[2]	2.7	[2]	24.1	[3]	8	[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		0.8
Interest cost		0.2		0.2		0.5		0.5
Expected return on plan assets		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		0.1		0.1
Settlement		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		0.1		0.1
Net periodic benefit cost (net of unconsolidated affiliates)		0.8	[2]	0.6	[2]	2	[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		1
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		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).

Report of Business Segments (De

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		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)	[2]	131.9	[2]
Other income (expense)	5.8		2.5		16.3		3.5
Interest expense	37		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		337.3		343.1
Depreciation and amortization	75.9		69.4		224		198.7
Taxes other than income	21		20.6		65.7		63.1
OPERATING INCOME	255.7		248.4		440.5		452.4
Equity in earnings of unconsolidated affiliates (A)	0	[1]	0	[1]	0	[2]	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		58.7		94.9		95.3
Net income (loss)	162.9		157.3		249		254.9
Investment in unconsolidated affiliates	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
Cost of sales	0		0		0		0
Other operation and maintenance	4.9		0.3		5.9		0.7
Depreciation and amortization	0		0		0		0
Taxes other than income	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)	[2]	131.9	[2]
Other income (expense)	0		0		0		0
Interest expense	0		0		0		0
Income tax expense	(26.8)		16.2		(8.7)		49.6
Net income (loss)	(50)		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
Cost of sales	0		0		0		0
Other operation and maintenance	(2.9)		(3.2)		(8.9)		(11.9)
Depreciation and amortization	2		2.3		6		8.5
Taxes other than income	0.9		0.9		3.1		3.4
OPERATING INCOME	0		0		(0.2)		0
Equity in earnings of unconsolidated affiliates (A)	0	[1]	0	[1]	0	[2]	0	[2]
Other income (expense)	(0.7)		(0.3)		2.6		(0.8)
Interest expense	0.7		2		2.1		6
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
Total assets	134		204.1		134		204.1
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0		0		0		0
Cost of sales	0		0		0		0
Other operation and maintenance	0		0		0		0
Depreciation and amortization	0		0		0		0
Taxes other than income	0		0		0		0
OPERATING INCOME	0		0		0		0
Equity in earnings of unconsolidated affiliates (A)	0	[1]	0	[1]	0	[2]	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
Net income (loss)	0		0		0		0
Investment in unconsolidated affiliates	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.

Commitments and Contingencies (

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%

Rate Matters and Regulation Rat

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