OGE Energy (OGE) 10-Q 3 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2016shares
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,702,959

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
OPERATING REVENUES	$ 743.9	$ 719.8	$ 1,728.4	$ 1,749.8
COST OF SALES	269.8	259.8	645.4	682.3
OPERATING EXPENSES
Other operation and maintenance	113.1	109.4	354.6	334.3
Depreciation and amortization	82.2	77.9	240.8	230
Taxes other than income	21.5	21.9	66.5	68.8
Total operating expenses	216.8	209.2	661.9	633.1
OPERATING INCOME	257.3	250.8	421.1	434.4
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	34.5	(71.9)	79.5	(12)
Allowance for equity funds used during construction	3.9	2.2	9.2	5.4
Other income	5.7	8.9	18.9	19.4
Other expense	(3.3)	(5.3)	(10.8)	(8.5)
Net other income (expense)	40.8	(66.1)	96.8	4.3
INTEREST EXPENSE
Interest on long-term debt	35.8	37	107.3	110.9
Allowance for borrowed funds used during construction	(2)	(1.1)	(4.7)	(2.7)
Interest on short-term debt and other interest charges	1.6	1.1	5.1	4.2
Interest expense	35.4	37	107.7	112.4
INCOME BEFORE TAXES	262.7	147.7	410.2	326.3
INCOME TAX EXPENSE	79.1	36.5	129.9	84.4
NET INCOME	$ 183.6	$ 111.2	$ 280.3	$ 241.9
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7	199.7	199.7	199.6
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.9	199.7	199.8	199.6
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.92	$ 0.55	$ 1.40	$ 1.21
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.92	0.55	1.40	1.21
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.30250	$ 0.27500	$ 0.85250	$ 0.77500

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net income	$ 183.6	$ 111.2	$ 280.3	$ 241.9
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4, $0.3, $1.2 and $1.7, respectively	0.8	0.7	2.3	1.9
Settlement cost, net of tax of $0.0, $2.4, $3.2 and $2.4, respectively	0	3.8	5	3.8
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.0, $0.2, $0.0 and $0.6, respectively	0	0.3	0	0.9
Amortization of prior service cost, net of tax of ($0.2), ($0.3), ($0.7) and ($0.8), respectively	(0.4)	(0.4)	(1.2)	(1.3)
Other comprehensive income, net of tax	0.4	4.4	6.1	5.3
Comprehensive income	$ 184	$ 115.6	$ 286.4	$ 247.2

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.4	$ 0.3	$ 1.2	$ 1.7
Settlement cost	0	2.4	3.2	2.4
Postretirement Benefit Plans:
Amortization of deferred net loss	0	0.2	0	0.6
Amortization of prior service cost	(0.2)	(0.3)	(0.7)	(0.8)
Amortization of deferred interest rate swap hedging losses	$ 0	$ 0	$ 0	$ 0

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 280.3	$ 241.9
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	240.8	230
Deferred income taxes and investment tax credits	134.2	62.3
Equity in earnings of unconsolidated affiliates	(79.5)	12
Distributions from unconsolidated affiliates	79.9	67.1
Allowance for equity funds used during construction	(9.2)	(5.4)
Stock-based compensation	3.2	3.8
Excess tax benefit on stock-based compensation	0	(5.2)
Regulatory assets	(10.5)	12.7
Regulatory liabilities	(9.8)	(13.9)
Other assets	18	12.7
Other liabilities	(19.8)	0.1
Change in certain current assets and liabilities
Accounts receivable, net	(51.2)	(33.8)
Accounts receivable - unconsolidated affiliates	(0.7)	0.5
Accrued unbilled revenues	(17.5)	(22.4)
Fuel, materials and supplies inventories	30.9	(25.5)
Fuel clause under recoveries	(0.5)	66.7
Other current assets	(13.1)	(8.9)
Accounts payable	(90.6)	(57.7)
Fuel clause over recoveries	(59.9)	34.5
Other current liabilities	1.9	37.6
Net Cash Provided from Operating Activities	426.9	609.1
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(466.7)	(375)
Return of capital - equity method investments	25.9	36.9
Proceeds from sale of assets	0.3	2.2
Net Cash Used in Investing Activities	(440.5)	(335.9)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(164.7)	(149.7)
Issuance of common stock	0	7.2
Excess tax benefit on stock-based compensation	0	5.2
Payment of long-term debt	(110.1)	(0.1)
Increase (decrease) in short-term debt	213.2	(98)
Net Cash Used in Financing Activities	(61.6)	(235.4)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(75.2)	37.8
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2	5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0	$ 43.3

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 0	$ 75.2
Accounts receivable, less reserve of $2.0 and $1.4, respectively	224.3	173.1
Accounts receivable - unconsolidated affiliates	2.4	1.7
Accrued unbilled revenues	71	53.5
Income taxes receivable	17.7	17.2
Fuel inventories	87.6	113.8
Materials and supplies, at average cost	75.4	80.1
Fuel clause under recoveries	0.5	0
Other	68.2	55.6
Total current assets	547.1	570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,168	1,194.4
Other	72	70.7
Total other property and investments	1,240	1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,599.6	10,318.3
Construction work in progress	365.8	278.5
Total property, plant and equipment	10,965.4	10,596.8
Less accumulated depreciation	3,431.1	3,274.4
Net property, plant and equipment	7,534.3	7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	404.8	402.2
Other	57.8	20.7
Total deferred charges and other assets	462.6	422.9
TOTAL ASSETS	9,784	9,580.6
CURRENT LIABILITIES
Short-term debt	213.2	0
Accounts payable	129.4	262.5
Dividends payable	60.4	54.9
Customer deposits	77.4	77
Accrued taxes	58.7	45.9
Accrued interest	33	42.9
Accrued compensation	34.1	54.4
Long-term debt due within one year	124.9	110
Fuel clause over recoveries	1.4	61.3
Other	62.8	43.9
Total current liabilities	795.3	752.8
LONG-TERM DEBT	2,505.2	2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	280.2	299.9
Deferred income taxes	2,314.5	2,178.2
Regulatory liabilities	292	273.6
Other	151.6	121.3
Total deferred credits and other liabilities	3,038.3	2,873
Total liabilities	6,338.8	6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,104.4	1,101.3
Retained earnings	2,369.8	2,259.8
Accumulated other comprehensive loss, net of tax	(29)	(35.1)
Total stockholders' equity	3,445.2	3,326
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 9,784	$ 9,580.6

CONDENSED CONSOLIDATED BALANCE7

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Allowance for Doubtful Accounts Receivable	$ 2	$ 1.4

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, 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)
Balance at Dec. 31, 2015	3,326	2	1,099.3	2,259.8	(35.1)
Changes in Stockholders' Equity
Net income	280.3	0	0	280.3	0
Other comprehensive income, net of tax	6.1	0	0	0	6.1
Dividends declared on common stock	(170.3)	0	0	(170.3)	0
Stock-based compensation	3.1	0	3.1	0	0
Balance at Sep. 30, 2016	$ 3,445.2	$ 2	$ 1,102.4	$ 2,369.8	$ (29)

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	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 the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and lacks the power to direct activities that most significantly impact economic performance. 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 Fort Smith, Arkansas and the surrounding communities. 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 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 of North Dakota. 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 the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group 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 the Company, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting 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, 2016 and December 31, 2015 , the results of its operations for the three and nine months ended September 30, 2016 and 2015 and its cash flows for the nine months ended September 30, 2016 and 2015 , 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, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 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 2015 Form 10-K.
Schedule of Regulatory Assets and Liabilities	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 incurred 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 incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. The following table is a summary of OG&E's regulatory assets and liabilities at: September 30, December 31, (In millions) 2016 2015 Regulatory Assets Current Oklahoma demand program rider under recovery (A) $ 48.9 $ 36.6 SPP cost tracker rider under recovery (A) 2.4 4.5 Fuel clause under recoveries 0.5 — Other (A) 7.6 5.4 Total Current Regulatory Assets $ 59.4 $ 46.5 Non-Current Benefit obligations regulatory asset $ 235.0 $ 242.2 Income taxes recoverable from customers, net 60.0 56.7 Smart Grid 43.4 43.6 Deferred storm expenses 35.9 27.6 Unamortized loss on reacquired debt 13.7 14.8 Other 16.8 17.3 Total Non-Current Regulatory Assets $ 404.8 $ 402.2 Regulatory Liabilities Current Fuel clause over recoveries $ 1.4 $ 61.3 Other (B) 3.8 7.5 Total Current Regulatory Liabilities $ 5.2 $ 68.8 Non-Current Accrued removal obligations, net $ 260.1 $ 254.9 Pension tracker 30.9 17.7 Other (C) 1.0 1.0 Total Non-Current Regulatory Liabilities $ 292.0 $ 273.6 (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 $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations The following table summarizes changes to the Company's asset retirement obligations during the nine months ended September 30, 2016 and 2015 . Nine Months Ended September 30, (In millions) 2016 2015 Balance at January 1 $ 63.3 $ 58.6 Accretion expense 2.1 1.9 Liabilities settled (0.2 ) (0.4 ) Revisions in estimated cash flows — 1.6 Balance at September 30 $ 65.2 $ 61.7
Comprehensive Income (Loss) Note [Text Block]	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, 2016 and 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 Net income Prior service cost Total Balance at December 31, 2015 $ (39.2 ) $ 0.1 $ 2.5 $ 1.5 $ (35.1 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.3 — — (1.2 ) 1.1 Settlement cost 5.0 — — — 5.0 Net current period other comprehensive income (loss) 7.3 — — (1.2 ) 6.1 Balance at September 30, 2016 $ (31.9 ) $ 0.1 $ 2.5 $ 0.3 $ (29.0 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net loss Prior service 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 — 0.9 (1.3 ) 1.5 Settlement cost 3.8 — — — 3.8 Net current period other comprehensive income (loss) 5.7 — 0.9 (1.3 ) 5.3 Balance at September 30, 2015 $ (31.1 ) $ 0.1 $ (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, 2016 and 2015 . 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) 2016 2015 2016 2015 Amortization of defined benefit pension and restoration of retirement income plan items Actuarial losses $ (1.2 ) $ (1.0 ) $ (3.5 ) $ (3.6 ) (A) Settlement — (6.2 ) (8.2 ) (6.2 ) (A) (1.2 ) (7.2 ) (11.7 ) (9.8 ) Total before tax (0.4 ) (2.7 ) (4.4 ) (4.1 ) Tax benefit $ (0.8 ) $ (4.5 ) $ (7.3 ) $ (5.7 ) Net of tax Amortization of postretirement benefit plan items Actuarial losses $ — $ (0.5 ) $ — $ (1.5 ) (A) Prior service credit 0.6 0.7 1.9 2.1 (A) 0.6 0.2 1.9 0.6 Total before tax 0.2 0.1 0.7 0.2 Tax expense $ 0.4 $ 0.1 $ 1.2 $ 0.4 Net of tax Total reclassifications for the period $ (0.4 ) $ (4.4 ) $ (6.1 ) $ (5.3 ) 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).
Reclassifications [Text Block]	Reclassifications Certain prior-year amounts have been reclassified to conform to the current year presentation. The December 31, 2015 Condensed Consolidated Balance Sheet has been adjusted for the reclassification of $16.8 million of debt issuance costs from Total Deferred Charges and Other Assets to Long-Term Debt to be consistent with the 2016 presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," in 2016 .

Accounting Pronouncements

Accounting Pronouncements	9 Months Ended
	Sep. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting Pronouncements Revenue from Contracts with Customers. 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. 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. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has yet to select a transition method or determine the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material. Consolidation . In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810)". The amendments in ASU 2015-02 affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. The new standard modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities along with eliminating the presumption that a general partner should consolidate a limited partnership. The new standard is effective for fiscal years beginning after December 15, 2015. The adoption of this new standard did not result in the consolidation of any non-consolidated entities. Leases. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. The main difference between current lease accounting and Topic 842 is the recognition of right-to-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance . Lessees, such as the Company, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance, but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has started evaluating its current lease contracts. The Company has not determined the amount of impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities. Investments. In March 2016, the FASB issued ASU 2016-07, "Investments-Equity Method and Joint Ventures; Simplifying the Transition to the Equity Method of Accounting (Topic 323)." The amendments in ASU 2016-07 eliminate the requirement to retroactively adopt the equity method of accounting for a qualifying equity method investment. ASU 2016-07 requires equity method investors to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendments in this ASU are effective for the fiscal years and interim periods within those fiscal years, beginning after December 15, 2016. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements. Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends ASC Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements. The new guidance among other requirements will require all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then to the income statement. This change is required to be applied prospectively to all excess tax benefits and tax deficiencies resulting from settlements after the date of adoption of the ASU 2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. Early adoption will be permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. The Company has not determined the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material. Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments.” The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements .

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	Investment in Unconsolidated Affiliate The Company'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, the Company 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. The Company accounts for its 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. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at September 30, 2016 . The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. 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 and are classified as investing activities in the Condensed Consolidated Statements of Cash Flows. Investment in Unconsolidated Affiliate and Related Party Transactions On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013. Pursuant to the Master Formation Agreement, the Company 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. In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At September 30, 2016 , the Company owned 111.0 million common units, or 26.3 percent of which 68.2 million units were subordinated. The Company and CenterPoint also own a 60 percent and 40 percent interest, respectively, in the incentive distribution rights held by the general partner of Enable. Distributions received from Enable were $35.3 million and $35.1 million during the three months ended September 30, 2016 and 2015 , respectively, and $105.9 million and $104.0 million for the nine months ended September 30, 2016 and 2015 , respectively. On November 1, 2016, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, representing the same dividend distribution as the previous quarter. CenterPoint had previously announced that it was evaluating strategic alternatives for its investment in Enable. On July 18, 2016, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided notice to the Company of CenterPoint’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner. Under the terms of the right of first offer, the Company had 30 days from receipt of the notice from CenterPoint to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint Energy Resources Corp. common units and subordinated units. The Company submitted to CenterPoint a proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in Enable GP and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint within the required timeframe. Related Party Transactions Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below. On May 1, 2013, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement, and other agreements whereby the Company 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. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2016. Under these agreements, the Company charged operating costs to Enable of $1.0 million and $2.6 million for the three months ended September 30, 2016 and 2015 , respectively, and $3.6 million and $7.9 million for the nine months ended September 30, 2016 and 2015 , respectively. The Company 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 are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. Additionally, the Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, the Company, CenterPoint and Enable agreed to continue the secondment to Enable of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $6.6 million and $7.0 million during the three months ended September 30, 2016 and 2015 , respectively, and $20.7 million and $25.1 million during the nine months ended September 30, 2016 and 2015 , respectively, under the Transitional Seconding Agreement for employment costs. The Company had accounts receivable from Enable for amounts billed for transitional services, including the cost of seconded employees, of $3.7 million and $3.4 million as of September 30, 2016 and December 31, 2015 , respectively. Related Party Transactions with Enable OG&E entered into a contract with Enable to provide gas transportation services effective May 1, 2014. 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 Enable during the three and nine months ended September 30, 2016 and 2015 . Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2016 2015 2016 2015 Operating Revenues: Electricity to power electric compression assets $ 3.7 $ 4.4 $ 9.0 $ 11.1 Cost of Sales: Natural gas transportation services $ 8.8 $ 8.8 $ 26.3 $ 26.3 Natural gas purchases/(sales) 4.4 2.5 11.3 7.1 Summarized Financial Information of Enable Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 . September 30, December 31, Balance Sheet 2016 2015 (In millions) Current assets $ 408 $ 381 Non-current assets 10,833 10,845 Current liabilities 338 615 Non-current liabilities 3,174 3,080 Three Months Ended Nine Months Ended September 30, September 30, Income Statement 2016 2015 2016 2015 (In millions) Operating revenues $ 620 $ 646 $ 1,658 $ 1,852 Cost of natural gas and natural gas liquids 268 287 717 856 Operating income 139 (975 ) 299 (778 ) Net income 110 (985 ) 231 (817 ) The formation of Enable was considered a business combination and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value. Enogex Holdings' assets, liabilities and equity 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. The Company recorded equity in earnings of unconsolidated affiliates of $34.5 million and $79.5 million for the three and nine months ended September 30, 2016 , respectively, and a loss in equity in earnings of $71.9 million and $12.0 million for the three and nine months ended September 30, 2015 , respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in the 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 initial public offering 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 below. 2015 Goodwill Impairment. Enable tested its goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicated that the carrying value of goodwill may not be recoverable. Goodwill was 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, 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 , and wrote off all of its goodwill in the third quarter of 2015. The following table reconciles the Company's equity in earnings (loss) of its unconsolidated affiliates for the three and nine months ended September 30, 2016 and 2015 . Three Months Ended Nine Months Ended September 30, September 30, Reconciliation of Equity in Earnings (Loss) of Unconsolidated Affiliates 2016 2015 2016 2015 (In millions) Enable net income (loss) $ 110.1 $ (985.1 ) $ 230.8 $ (817.3 ) Distributions senior to limited partners (9.1 ) — (9.1 ) — Differences due to timing of OGE Energy and Enable accounting close and permanent items 3.0 4.2 (3.6 ) 9.9 Enable net income (loss) used to calculate OGE Energy's equity in earnings $ 104.0 $ (980.9 ) $ 218.1 $ (807.4 ) OGE Energy’s percent ownership 26.3 % 26.3 % 26.3 % 26.3 % OGE Energy’s portion of Enable net income (loss) $ 27.3 $ (257.2 ) $ 57.5 $ (212.0 ) Impairments recognized by Enable associated with OGE Energy’s basis differences — 177.7 0.6 177.7 OGE Energy's share of Enable net income (loss) $ 27.3 $ (79.5 ) $ 58.1 $ (34.3 ) Amortization of basis difference 2.9 3.5 8.8 10.6 Elimination of Enable fair value step up 4.3 4.1 12.6 11.7 Equity in earnings (loss) of unconsolidated affiliates $ 34.5 $ (71.9 ) $ 79.5 $ (12.0 )

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
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, 2016 and December 31, 2015 . The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2016 and December 31, 2015 . September 30, December 31, 2016 2015 (In millions) Carrying Amount Fair Carrying Amount Fair Long-Term Debt Senior Notes $ 2,385.0 $ 2,818.2 $ 2,493.9 $ 2,754.6 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.9 10.0 10.0 9.2 OGE Energy Senior Notes 99.8 99.9 99.5 99.9 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 is 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, 2016
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, 2016 and 2015 related to the Company's performance units and restricted stock . Three Months Ended September 30, Nine Months Ended September 30, (In millions) 2016 2015 2016 2015 Performance units Total shareholder return $ 1.2 $ 1.9 $ 3.4 $ 5.7 Earnings per share (1.3 ) (0.8 ) (0.3 ) 0.3 Total performance units (0.1 ) 1.1 3.1 6.0 Restricted stock — — 0.1 0.1 Total compensation expense (0.1 ) 1.1 3.2 6.1 Less: Amount paid by unconsolidated affiliates — (0.2 ) — 0.3 Net compensation expense $ (0.1 ) $ 1.3 $ 3.2 $ 5.8 Income tax benefit $ — $ 0.5 $ 1.3 $ 2.3 During the three and nine months ended September 30, 2016 , the Company issued an immaterial number of shares to satisfy restricted stock grants.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
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 2013 or state and local tax examinations by tax authorities for years prior to 2012 . Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E 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.

Common Equity

Common Equity	9 Months Ended
	Sep. 30, 2016
Common Equity [Text Block]	Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months ended September 30, 2016 . Earnings Per Share Basic earnings per share is calculated by dividing net income attributable to the Company 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) 2016 2015 2016 2015 Net income $ 183.6 $ 111.2 $ 280.3 $ 241.9 Average Common Shares Outstanding Basic average common shares outstanding 199.7 199.7 199.7 199.6 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.2 — 0.1 — Diluted average common shares outstanding 199.9 199.7 199.8 199.6 Basic Earnings Per Average Common Share $ 0.92 $ 0.55 $ 1.40 $ 1.21 Diluted Earnings Per Average Common Share $ 0.92 $ 0.55 $ 1.40 $ 1.21 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	Long-Term Debt At September 30, 2016 , 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% - 0.84% Garfield Industrial Authority, January 1, 2025 $ 47.0 0.07% - 0.80% Muskogee Industrial Authority, January 1, 2025 32.4 0.05% - 0.82% 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, 2016
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 agreement. As of September 30, 2016 , the Company had $213.2 million of short-term debt as compared to no balance at December 31, 2015 . The following table provides information regarding the Company's revolving credit agreements at September 30, 2016 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Maturity (In millions) OGE Energy (B) $ 750.0 $ 213.2 0.74 % (D) December 13, 2018 (E) OG&E (C) 400.0 1.7 0.95 % (D) December 13, 2018 (E) Total $ 1,150.0 $ 214.9 0.74 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2016 . (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. (E) As of September 30, 2016 , commitments of $16.3 million and $8.7 million of the OGE Energy's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017 . The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post 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 $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016. OG&E has requested renewal of this authority for an additional two-year period and expects to receive approval prior to the expiration of its current authority.

Retirement Plans and Postretire

Retirement Plans and Postretirement Benefit Plans	9 Months Ended
	Sep. 30, 2016
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 a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.7 million during the nine months ended September 30, 2016 . 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 increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods. 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) 2016 (B) 2015 (B) 2016 (C) 2015 (C) 2016 (B) 2015 (B) 2016 (C) 2015 (C) Service cost $ 4.0 $ 4.2 $ 11.9 $ 12.1 $ — $ 0.4 $ 0.2 $ 1.0 Interest cost 6.4 6.6 19.1 19.6 0.1 0.2 0.3 0.5 Expected return on plan assets (10.4 ) (11.0 ) (31.1 ) (34.5 ) — — — — Amortization of net loss 4.1 3.8 12.3 13.5 0.2 0.2 0.5 0.5 Amortization of unrecognized prior service cost (A) (0.1 ) 0.1 (0.1 ) 0.3 0.1 — 0.1 0.1 Settlement — 16.2 — 16.2 — — 8.7 — Total net periodic benefit cost 4.0 19.9 12.1 27.2 0.4 0.8 9.8 2.1 Less: Amount paid by unconsolidated affiliates 1.3 1.0 3.8 3.1 0.1 — 0.3 0.1 Net periodic benefit cost (net of unconsolidated affiliates) $ 2.7 $ 18.9 $ 8.3 $ 24.1 $ 0.3 $ 0.8 $ 9.5 $ 2.0 (A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment. (B) In addition to the $3.0 million and $19.7 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015 , respectively , OG&E recognized the following: • an increase in pension expense during the three months ended September 30, 2016 of $2.4 million and a deferral of $4.7 million for the three months ended September 30, 2015 , 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); and • during the three months ended September 30, 2016 there were no costs relating to the deferral of pension expense compared to $1.4 million for the three months ended September 30, 2015 related to the Arkansas jurisdictional portion of the pension settlement charge of $16.2 million during the three months ended September 30, 2015 . (C) In addition to the $17.8 million and $26.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015 , respectively , OG&E recognized the following: • an increase in pension expense during the nine months ended September 30, 2016 and 2015 of $6.7 million and $0.6 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); and • costs relating to the deferral of pension expense during the nine months ended September 30, 2016 and 2015 of $0.1 million and $1.4 million , respectively, related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million and $16.2 million , respectively. Postretirement Benefit Plans Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2016 (B) 2015 (B) 2016 (C) 2015 (C) Service cost $ 0.2 $ 0.4 $ 0.6 $ 1.2 Interest cost 2.4 2.6 7.1 7.7 Expected return on plan assets (0.6 ) (0.6 ) (1.7 ) (1.8 ) Amortization of net loss 0.6 3.5 1.9 10.4 Amortization of unrecognized prior service cost (A) (2.1 ) (4.1 ) (6.5 ) (12.4 ) Total net periodic benefit cost 0.5 1.8 1.4 5.1 Less: Amount paid by unconsolidated affiliates — 0.4 0.1 1.0 Net periodic benefit cost (net of unconsolidated affiliates) $ 0.5 $ 1.4 $ 1.3 $ 4.1 (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 $0.5 million and $1.4 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015 , respectively, OG&E recognized an increase in postretirement medical expense during the three months ended September 30, 2016 and 2015 of $1.9 million and $1.4 million , respectively , to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1). (C) In addition to the $1.3 million and $4.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015 , respectively, OG&E recognized an increase in postretirement medical expense during the nine months ended September 30, 2016 and 2015 of $5.9 million and $4.3 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). Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2016 2015 2016 2015 Capitalized portion of net periodic pension benefit cost $ 1.0 $ 2.6 $ 3.0 $ 4.6 Capitalized portion of net periodic postretirement benefit cost 0.2 0.5 0.6 1.4 Pension Plan Funding In July 2016 , the Company contributed $20.0 million to its Pension Plan . No additional contributions are expected in 2016.

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. 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, 2016 and 2015 . Three Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 743.9 $ — $ — $ — $ 743.9 Cost of sales 269.8 — — — 269.8 Other operation and maintenance 115.2 (0.1 ) (2.0 ) — 113.1 Depreciation and amortization 80.8 — 1.4 — 82.2 Taxes other than income 20.9 — 0.6 — 21.5 Operating income 257.2 0.1 — — 257.3 Equity in earnings of unconsolidated affiliates — 34.5 — — 34.5 Other income 6.0 — 0.3 — 6.3 Interest expense 34.3 — 1.1 — 35.4 Income tax expense (benefit) 69.0 12.1 (2.0 ) — 79.1 Net income $ 159.9 $ 22.5 $ 1.2 $ — $ 183.6 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0 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 255.7 (4.9 ) — — 250.8 Equity in earnings of unconsolidated affiliates (A) — (71.9 ) — — (71.9 ) Other income 6.6 — (0.7 ) (0.1 ) 5.8 Interest expense 36.4 — 0.7 (0.1 ) 37.0 Income tax expense (benefit) 63.0 (26.8 ) 0.3 — 36.5 Net income $ 162.9 $ (50.0 ) $ (1.7 ) $ — $ 111.2 Investment in unconsolidated affiliates $ — $ 1,202.2 $ — $ — $ 1,202.2 Total assets $ 8,554.1 $ 1,541.5 $ 133.5 $ (628.4 ) $ 9,600.7 (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. Nine Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,728.4 $ — $ — $ — $ 1,728.4 Cost of sales 645.4 — — — 645.4 Other operation and maintenance 356.3 7.9 (9.6 ) — 354.6 Depreciation and amortization 235.9 — 4.9 — 240.8 Taxes other than income 63.6 — 2.9 — 66.5 Operating income 427.2 (7.9 ) 1.8 — 421.1 Equity in earnings of unconsolidated affiliates — 79.5 — — 79.5 Other income 18.3 — (0.8 ) (0.2 ) 17.3 Interest expense 104.8 — 3.1 (0.2 ) 107.7 Income tax expense (benefit) 102.4 31.5 (4.0 ) — 129.9 Net income $ 238.3 $ 40.1 $ 1.9 $ — $ 280.3 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0 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 440.5 (5.9 ) (0.2 ) — 434.4 Equity in earnings of unconsolidated affiliates (A) — (12.0 ) — — (12.0 ) Other income 13.9 — 2.6 (0.2 ) 16.3 Interest expense 110.5 — 2.1 (0.2 ) 112.4 Income tax expense (benefit) 94.9 (8.7 ) (1.8 ) — 84.4 Net income $ 249.0 $ (9.2 ) $ 2.1 $ — $ 241.9 Investment in unconsolidated affiliates $ — $ 1,202.2 $ — $ — $ 1,202.2 Total assets $ 8,554.1 $ 1,541.5 $ 133.5 $ (628.4 ) $ 9,600.7 (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.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
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 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities. Environmental Laws and Regulations The activities of OG&E are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards. Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its condensed financial position or results of operations. The Company believes, however, that it is likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. Federal Clean Air Act New Source Review Litigation 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, on behalf of the EPA, 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. This complaint sought to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club intervened in this proceeding. On August 30, 2013, the government filed a Motion for Summary Judgment and on September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, the Court dismissed the complaints filed by the EPA and the Sierra Club. The Court held that it lacked subject matter jurisdiction over 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 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 sought a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the District Court 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 District Court to dismiss its remaining claims with prejudice. On August 27, 2014, the District Court granted the Sierra Club's request. The Sierra Club appealed the District Court's dismissal of its prevention of significant deterioration claim to the United States Court of Appeals for the Tenth Circuit. On March 8, 2016, the Tenth Circuit affirmed the trial court's decision dismissing the Sierra Club's case. On March 21, 2016, the Sierra Club filed a request for rehearing en banc with the Tenth Circuit. On April 13, 2016, the Tenth Circuit denied the request for rehearing. The Sierra Club did not seek review of the case by the United States Supreme Court. OG&E considers this case now closed. 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 dry scrubber systems. The dry scrubbers are scheduled to be completed by 2019. More detail regarding the dry scrubber project can be found under “Pending Regulatory Matters” in Note 13. 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 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, 2016
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 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. Completed Regulatory Matters FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule. Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities. The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement. On July 1, 2016, the Court upheld the FERC's decision requiring removal of the rights of first refusal for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the rights of first refusal in the SPP Membership Agreement to be anticompetitive. The Company does not believe the Court’s ruling will have any impact on existing transmission projects for which the Company has already received a notice to construct from the SPP. The Company intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV. 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. On May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. Oklahoma Demand Program Rider Review - SmartHours Program 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 PUD Staff's review. In March 2014, the PUD Staff began their review of the Demand Program costs, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the 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 and beyond. In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues (approximately $10.0 million annually). In April 2015, the PUD Staff filed an application, seeking an order from the OCC, for determining the proper methodology for calculating lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues. In the application, the PUD Staff recommended the OCC approve the PUD Staff's methodology for calculating lost revenues associated with the SmartHours program, which differed from the methodology that OG&E believes it agreed upon and which would result in recovery of significantly less lost revenue for 2013, 2014 and 2015 than OG&E had recorded. On March 28, 2016, the ALJ issued her recommendation on the PUD Staff's application. She found, among other things, that OG&E and the PUD Staff had not reached an agreement on all aspects of the calculation of lost revenues, that OG&E’s methodology for calculating lost revenues was not consistent with the provisions of OG&E’s tariff, and that the PUD Staff’s methodology for calculating lost revenues was proper. The ALJ recommended that the OCC order OG&E to adjust its calculation of SmartHours lost revenue for 2013 through 2015 consistent with the PUD Staff’s methodology, but that such adjustment should only be applied on a prospective basis following the issuance of an order by the OCC. On August 9, 2016, OG&E entered into a settlement agreement with the PUD Staff to resolve the recoverable amount of lost revenues associated with the SmartHours program. The settlement provides for recovery of $10.1 million per year for 2013, 2014 and 2015, for a total of $30.3 million . OG&E had recorded $36.6 million of lost revenues for 2013, 2014 and 2015. On August 16, 2016, the OCC issued an order adopting the settlement agreement. Accordingly, OG&E reduced lost revenues and the Oklahoma Demand Program Rider regulatory asset by $6.3 million . Mustang Modernization Plan-Arkansas On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas. The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings. In July 2016, OG&E filed a motion to dismiss the APSC Mustang proceeding and in August, the APSC approved the dismissal. OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service. Pending Regulatory Matters Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates. 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 Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP 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 asked the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 with 400 MWs of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015, approximately seven months after OG&E filed its application, and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding. On June 8, 2015, the ALJ issued his report on OG&E's application. While the ALJ in his report agreed 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 ECP is the best approach, the ALJ's report included several recommendations. OG&E filed exceptions to the ALJ's report and on July 21, 2015, Commissioner Bob Anthony issued his deliberation statement that was consistent with many parts of the ALJ's report, including the ALJ’s support of OG&E’s ECP, the ALJ’s recommendation to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other cost recovery issues until the next general rate case. On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider. On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP. OG&E did not seek modification to any other provisions of the OCC order, including cost recovery. OG&E also agreed that it would not implement a rider for recovery of the costs of the ECP until and unless authorized by the OCC in a subsequent proceeding. On December 23, 2015, the OCC rejected, by a two to one vote, a proposal by Commissioner Dana Murphy to grant OG&E's December 11, 2015 motion. On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install dry scrubbers at the Sooner facility on or before May 2, 2016. OG&E's application did not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Two parties to the proceeding have appealed the OCC's decision to the Oklahoma Supreme Court. After the OCC provides a certified record to the Oklahoma Supreme Court, the parties will file briefs by the end of 2016 or the first quarter of 2017. OG&E anticipates the total cost of dry scrubbers will be $547.5 million . As of September 30, 2016 , OG&E had invested $138.6 million of construction work in progress on the dry scrubbers. OG&E anticipates the combustion turbines for the Mustang Modernization Plan will be $424.9 million . As of September 30, 2016 , OG&E has invested $133.6 million on the Mustang Modernization Plan. 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 ECP and other parts of the action plan contained in the IRP submitted in 2014. Oklahoma Rate Case Filing As previously reported in the Company's 2015 Form 10-K, on December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53 percent . The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million . Each 0.25 percent change in the requested return on equity affects the requested rate increase by approximately $9.0 million . In late March 2016, the PUD Staff and other intervenors filed testimony in the case. The PUD Staff recommended a $6.1 million annual rate increase based on a return on equity of 9.25 percent and a common equity percentage of 53.0 percent . Included in the PUD Staff's recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement. The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent , as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent . Included in the Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement. The Oklahoma Industrial Electric Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent . Included in the Oklahoma Industrial Electric Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement. The hearings in this matter began on May 3, 2016. While there is no statutory deadline for the ALJ to make a recommendation or for the commission to issue a final order, OG&E is allowed to implement increased rates subject to refund 180 days after the filing of its application on December 18, 2015. On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million while simultaneously reducing fuel costs billed to customers. The interim rates are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case. As of September 30, 2016 , the Company has recorded $23.6 million of revenues from the interim rate increase and has reserved $21.0 million of that revenue. Arkansas Rate Case Filing On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management, and increased recovery of depreciation and dismantlement costs. OG&E has a hearing scheduled for the rate case in the second quarter of 2017. Fuel Adjustment Clause Review for Calendar Year 2015 On September 8, 2016, the OCC staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. OG&E has verbally agreed to a March 9, 2017 hearing date.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2016
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 the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and lacks the power to direct activities that most significantly impact economic performance. 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 Fort Smith, Arkansas and the surrounding communities. 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 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 of North Dakota. 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 the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group 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 the Company, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.
Basis of Accounting, Policy [Policy 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, 2016 and December 31, 2015 , the results of its operations for the three and nine months ended September 30, 2016 and 2015 and its cash flows for the nine months ended September 30, 2016 and 2015 , 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, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 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 2015 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 incurred 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 incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Equity Method Investments, Policy [Policy Text Block]	Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting. Investment in Unconsolidated Affiliate The Company'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, the Company 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. The Company accounts for its 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. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at September 30, 2016 . The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. 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 and 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 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 is 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]	The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E 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.
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Share Basic earnings per share is calculated by dividing net income attributable to the Company 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, 2016
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: September 30, December 31, (In millions) 2016 2015 Regulatory Assets Current Oklahoma demand program rider under recovery (A) $ 48.9 $ 36.6 SPP cost tracker rider under recovery (A) 2.4 4.5 Fuel clause under recoveries 0.5 — Other (A) 7.6 5.4 Total Current Regulatory Assets $ 59.4 $ 46.5 Non-Current Benefit obligations regulatory asset $ 235.0 $ 242.2 Income taxes recoverable from customers, net 60.0 56.7 Smart Grid 43.4 43.6 Deferred storm expenses 35.9 27.6 Unamortized loss on reacquired debt 13.7 14.8 Other 16.8 17.3 Total Non-Current Regulatory Assets $ 404.8 $ 402.2 Regulatory Liabilities Current Fuel clause over recoveries $ 1.4 $ 61.3 Other (B) 3.8 7.5 Total Current Regulatory Liabilities $ 5.2 $ 68.8 Non-Current Accrued removal obligations, net $ 260.1 $ 254.9 Pension tracker 30.9 17.7 Other (C) 1.0 1.0 Total Non-Current Regulatory Liabilities $ 292.0 $ 273.6 (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 $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities.
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, 2016 and 2015 . Nine Months Ended September 30, (In millions) 2016 2015 Balance at January 1 $ 63.3 $ 58.6 Accretion expense 2.1 1.9 Liabilities settled (0.2 ) (0.4 ) Revisions in estimated cash flows — 1.6 Balance at September 30 $ 65.2 $ 61.7
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, 2016 and 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 Net income Prior service cost Total Balance at December 31, 2015 $ (39.2 ) $ 0.1 $ 2.5 $ 1.5 $ (35.1 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.3 — — (1.2 ) 1.1 Settlement cost 5.0 — — — 5.0 Net current period other comprehensive income (loss) 7.3 — — (1.2 ) 6.1 Balance at September 30, 2016 $ (31.9 ) $ 0.1 $ 2.5 $ 0.3 $ (29.0 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net loss Prior service 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 — 0.9 (1.3 ) 1.5 Settlement cost 3.8 — — — 3.8 Net current period other comprehensive income (loss) 5.7 — 0.9 (1.3 ) 5.3 Balance at September 30, 2015 $ (31.1 ) $ 0.1 $ (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, 2016 and 2015 . 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) 2016 2015 2016 2015 Amortization of defined benefit pension and restoration of retirement income plan items Actuarial losses $ (1.2 ) $ (1.0 ) $ (3.5 ) $ (3.6 ) (A) Settlement — (6.2 ) (8.2 ) (6.2 ) (A) (1.2 ) (7.2 ) (11.7 ) (9.8 ) Total before tax (0.4 ) (2.7 ) (4.4 ) (4.1 ) Tax benefit $ (0.8 ) $ (4.5 ) $ (7.3 ) $ (5.7 ) Net of tax Amortization of postretirement benefit plan items Actuarial losses $ — $ (0.5 ) $ — $ (1.5 ) (A) Prior service credit 0.6 0.7 1.9 2.1 (A) 0.6 0.2 1.9 0.6 Total before tax 0.2 0.1 0.7 0.2 Tax expense $ 0.4 $ 0.1 $ 1.2 $ 0.4 Net of tax Total reclassifications for the period $ (0.4 ) $ (4.4 ) $ (6.1 ) $ (5.3 ) 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, 2016
Related Party Transactions [Abstract]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]	The following table reconciles the Company's equity in earnings (loss) of its unconsolidated affiliates for the three and nine months ended September 30, 2016 and 2015 . Three Months Ended Nine Months Ended September 30, September 30, Reconciliation of Equity in Earnings (Loss) of Unconsolidated Affiliates 2016 2015 2016 2015 (In millions) Enable net income (loss) $ 110.1 $ (985.1 ) $ 230.8 $ (817.3 ) Distributions senior to limited partners (9.1 ) — (9.1 ) — Differences due to timing of OGE Energy and Enable accounting close and permanent items 3.0 4.2 (3.6 ) 9.9 Enable net income (loss) used to calculate OGE Energy's equity in earnings $ 104.0 $ (980.9 ) $ 218.1 $ (807.4 ) OGE Energy’s percent ownership 26.3 % 26.3 % 26.3 % 26.3 % OGE Energy’s portion of Enable net income (loss) $ 27.3 $ (257.2 ) $ 57.5 $ (212.0 ) Impairments recognized by Enable associated with OGE Energy’s basis differences — 177.7 0.6 177.7 OGE Energy's share of Enable net income (loss) $ 27.3 $ (79.5 ) $ 58.1 $ (34.3 ) Amortization of basis difference 2.9 3.5 8.8 10.6 Elimination of Enable fair value step up 4.3 4.1 12.6 11.7 Equity in earnings (loss) of unconsolidated affiliates $ 34.5 $ (71.9 ) $ 79.5 $ (12.0 )
Schedule of Related Party Transactions [Table Text Block]	The following table summarizes related party transactions between OG&E and Enable during the three and nine months ended September 30, 2016 and 2015 . Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2016 2015 2016 2015 Operating Revenues: Electricity to power electric compression assets $ 3.7 $ 4.4 $ 9.0 $ 11.1 Cost of Sales: Natural gas transportation services $ 8.8 $ 8.8 $ 26.3 $ 26.3 Natural gas purchases/(sales) 4.4 2.5 11.3 7.1
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, 2016 and December 31, 2015 and for the three and nine months ended September 30, 2016 and 2015 . September 30, December 31, Balance Sheet 2016 2015 (In millions) Current assets $ 408 $ 381 Non-current assets 10,833 10,845 Current liabilities 338 615 Non-current liabilities 3,174 3,080
Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, Income Statement 2016 2015 2016 2015 (In millions) Operating revenues $ 620 $ 646 $ 1,658 $ 1,852 Cost of natural gas and natural gas liquids 268 287 717 856 Operating income 139 (975 ) 299 (778 ) Net income 110 (985 ) 231 (817 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 and December 31, 2015 . September 30, December 31, 2016 2015 (In millions) Carrying Amount Fair Carrying Amount Fair Long-Term Debt Senior Notes $ 2,385.0 $ 2,818.2 $ 2,493.9 $ 2,754.6 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.9 10.0 10.0 9.2 OGE Energy Senior Notes 99.8 99.9 99.5 99.9

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 and 2015 related to the Company's performance units and restricted stock . Three Months Ended September 30, Nine Months Ended September 30, (In millions) 2016 2015 2016 2015 Performance units Total shareholder return $ 1.2 $ 1.9 $ 3.4 $ 5.7 Earnings per share (1.3 ) (0.8 ) (0.3 ) 0.3 Total performance units (0.1 ) 1.1 3.1 6.0 Restricted stock — — 0.1 0.1 Total compensation expense (0.1 ) 1.1 3.2 6.1 Less: Amount paid by unconsolidated affiliates — (0.2 ) — 0.3 Net compensation expense $ (0.1 ) $ 1.3 $ 3.2 $ 5.8 Income tax benefit $ — $ 0.5 $ 1.3 $ 2.3

Common Equity (Tables)

Common Equity (Tables)	9 Months Ended
	Sep. 30, 2016
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) 2016 2015 2016 2015 Net income $ 183.6 $ 111.2 $ 280.3 $ 241.9 Average Common Shares Outstanding Basic average common shares outstanding 199.7 199.7 199.7 199.6 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.2 — 0.1 — Diluted average common shares outstanding 199.9 199.7 199.8 199.6 Basic Earnings Per Average Common Share $ 0.92 $ 0.55 $ 1.40 $ 1.21 Diluted Earnings Per Average Common Share $ 0.92 $ 0.55 $ 1.40 $ 1.21 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
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% - 0.84% Garfield Industrial Authority, January 1, 2025 $ 47.0 0.07% - 0.80% Muskogee Industrial Authority, January 1, 2025 32.4 0.05% - 0.82% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4

Short-Term Debt and Credit Fa29

Short-Term Debt and Credit Facilities (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Maturity (In millions) OGE Energy (B) $ 750.0 $ 213.2 0.74 % (D) December 13, 2018 (E) OG&E (C) 400.0 1.7 0.95 % (D) December 13, 2018 (E) Total $ 1,150.0 $ 214.9 0.74 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2016 . (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. (E) As of September 30, 2016 , commitments of $16.3 million and $8.7 million of the OGE Energy's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017 .

Retirement Plans and Postreti30

Retirement Plans and Postretirement Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2016
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) 2016 (B) 2015 (B) 2016 (C) 2015 (C) 2016 (B) 2015 (B) 2016 (C) 2015 (C) Service cost $ 4.0 $ 4.2 $ 11.9 $ 12.1 $ — $ 0.4 $ 0.2 $ 1.0 Interest cost 6.4 6.6 19.1 19.6 0.1 0.2 0.3 0.5 Expected return on plan assets (10.4 ) (11.0 ) (31.1 ) (34.5 ) — — — — Amortization of net loss 4.1 3.8 12.3 13.5 0.2 0.2 0.5 0.5 Amortization of unrecognized prior service cost (A) (0.1 ) 0.1 (0.1 ) 0.3 0.1 — 0.1 0.1 Settlement — 16.2 — 16.2 — — 8.7 — Total net periodic benefit cost 4.0 19.9 12.1 27.2 0.4 0.8 9.8 2.1 Less: Amount paid by unconsolidated affiliates 1.3 1.0 3.8 3.1 0.1 — 0.3 0.1 Net periodic benefit cost (net of unconsolidated affiliates) $ 2.7 $ 18.9 $ 8.3 $ 24.1 $ 0.3 $ 0.8 $ 9.5 $ 2.0 (A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment. (B) In addition to the $3.0 million and $19.7 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015 , respectively , OG&E recognized the following: • an increase in pension expense during the three months ended September 30, 2016 of $2.4 million and a deferral of $4.7 million for the three months ended September 30, 2015 , 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); and • during the three months ended September 30, 2016 there were no costs relating to the deferral of pension expense compared to $1.4 million for the three months ended September 30, 2015 related to the Arkansas jurisdictional portion of the pension settlement charge of $16.2 million during the three months ended September 30, 2015 . (C) In addition to the $17.8 million and $26.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015 , respectively , OG&E recognized the following: • an increase in pension expense during the nine months ended September 30, 2016 and 2015 of $6.7 million and $0.6 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); and • costs relating to the deferral of pension expense during the nine months ended September 30, 2016 and 2015 of $0.1 million and $1.4 million , respectively, related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million and $16.2 million , respectively. Postretirement Benefit Plans Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2016 (B) 2015 (B) 2016 (C) 2015 (C) Service cost $ 0.2 $ 0.4 $ 0.6 $ 1.2 Interest cost 2.4 2.6 7.1 7.7 Expected return on plan assets (0.6 ) (0.6 ) (1.7 ) (1.8 ) Amortization of net loss 0.6 3.5 1.9 10.4 Amortization of unrecognized prior service cost (A) (2.1 ) (4.1 ) (6.5 ) (12.4 ) Total net periodic benefit cost 0.5 1.8 1.4 5.1 Less: Amount paid by unconsolidated affiliates — 0.4 0.1 1.0 Net periodic benefit cost (net of unconsolidated affiliates) $ 0.5 $ 1.4 $ 1.3 $ 4.1 (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 $0.5 million and $1.4 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015 , respectively, OG&E recognized an increase in postretirement medical expense during the three months ended September 30, 2016 and 2015 of $1.9 million and $1.4 million , respectively , to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1). (C) In addition to the $1.3 million and $4.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015 , respectively, OG&E recognized an increase in postretirement medical expense during the nine months ended September 30, 2016 and 2015 of $5.9 million and $4.3 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).
Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2016 2015 2016 2015 Capitalized portion of net periodic pension benefit cost $ 1.0 $ 2.6 $ 3.0 $ 4.6 Capitalized portion of net periodic postretirement benefit cost 0.2 0.5 0.6 1.4

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, 2016 and 2015 . Three Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 743.9 $ — $ — $ — $ 743.9 Cost of sales 269.8 — — — 269.8 Other operation and maintenance 115.2 (0.1 ) (2.0 ) — 113.1 Depreciation and amortization 80.8 — 1.4 — 82.2 Taxes other than income 20.9 — 0.6 — 21.5 Operating income 257.2 0.1 — — 257.3 Equity in earnings of unconsolidated affiliates — 34.5 — — 34.5 Other income 6.0 — 0.3 — 6.3 Interest expense 34.3 — 1.1 — 35.4 Income tax expense (benefit) 69.0 12.1 (2.0 ) — 79.1 Net income $ 159.9 $ 22.5 $ 1.2 $ — $ 183.6 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0 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 255.7 (4.9 ) — — 250.8 Equity in earnings of unconsolidated affiliates (A) — (71.9 ) — — (71.9 ) Other income 6.6 — (0.7 ) (0.1 ) 5.8 Interest expense 36.4 — 0.7 (0.1 ) 37.0 Income tax expense (benefit) 63.0 (26.8 ) 0.3 — 36.5 Net income $ 162.9 $ (50.0 ) $ (1.7 ) $ — $ 111.2 Investment in unconsolidated affiliates $ — $ 1,202.2 $ — $ — $ 1,202.2 Total assets $ 8,554.1 $ 1,541.5 $ 133.5 $ (628.4 ) $ 9,600.7 (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. Nine Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,728.4 $ — $ — $ — $ 1,728.4 Cost of sales 645.4 — — — 645.4 Other operation and maintenance 356.3 7.9 (9.6 ) — 354.6 Depreciation and amortization 235.9 — 4.9 — 240.8 Taxes other than income 63.6 — 2.9 — 66.5 Operating income 427.2 (7.9 ) 1.8 — 421.1 Equity in earnings of unconsolidated affiliates — 79.5 — — 79.5 Other income 18.3 — (0.8 ) (0.2 ) 17.3 Interest expense 104.8 — 3.1 (0.2 ) 107.7 Income tax expense (benefit) 102.4 31.5 (4.0 ) — 129.9 Net income $ 238.3 $ 40.1 $ 1.9 $ — $ 280.3 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0 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 440.5 (5.9 ) (0.2 ) — 434.4 Equity in earnings of unconsolidated affiliates (A) — (12.0 ) — — (12.0 ) Other income 13.9 — 2.6 (0.2 ) 16.3 Interest expense 110.5 — 2.1 (0.2 ) 112.4 Income tax expense (benefit) 94.9 (8.7 ) (1.8 ) — 84.4 Net income $ 249.0 $ (9.2 ) $ 2.1 $ — $ 241.9 Investment in unconsolidated affiliates $ — $ 1,202.2 $ — $ — $ 1,202.2 Total assets $ 8,554.1 $ 1,541.5 $ 133.5 $ (628.4 ) $ 9,600.7 (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.

Summary of Significant Accoun32

Summary of Significant Accounting Policies Equity Ownership (Details)	Sep. 30, 2016
CenterPoint [Member]
Percentage Share of Management Rights	50.00%
OGE Energy [Member]
Percentage Share of Management Rights	50.00%

Regulated Operations (Details)

Regulated Operations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause over recoveries		$ 1.4	$ 61.3
Fuel clause under recoveries		0.5	0
Current Regulatory Assets		59.4	46.5
Non-Current Regulatory Assets		404.8	402.2
Current Regulatory Liabilities		5.2	68.8
Non-Current Regulatory Liabilities		292	273.6
Prior Period Reclassification Adjustment		1
Other Regulatory Liability [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	3.8	7.5
Non-Current Regulatory Liabilities	[2]	1	1
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		260.1	254.9
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		30.9	17.7
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[3]	48.9	36.6
Other Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[3]	7.6	5.4
Non-Current Regulatory Assets		16.8	17.3
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		235	242.2
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		60	56.7
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		43.4	43.6
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		35.9	27.6
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		13.7	14.8
SPP Cost Tracker Rider Under Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[3]	$ 2.4	$ 4.5
[1]	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
[2]	Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities.
[3]	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.

Summary of Significant Accoun34

Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 63.3	$ 58.6
Accretion expense	2.1	1.9
Liabilities settled	(0.2)	(0.4)
Revisions in estimated cash flows	0	1.6
Balance at September 30	$ 65.2	$ 61.7

Summary of Significant Accoun35

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (29)	$ (36.1)	$ (35.1)	$ (41.4)
Amounts reclassified from accumulated other comprehensive income (loss)	1.1	1.5
Net current period other comprehensive income (loss)	6.1	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	(31.9)	(31.1)	(39.2)	(36.8)
Amounts reclassified from accumulated other comprehensive income (loss)	2.3	1.9
Net current period other comprehensive income (loss)	7.3	5.7
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	2.5	(7.1)	2.5	(8)
Amounts reclassified from accumulated other comprehensive income (loss)	0	0.9
Net current period other comprehensive income (loss)	0	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	0.1	0.1
Amounts reclassified from accumulated other comprehensive income (loss)	0	0
Net current period other comprehensive income (loss)	0	0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	0.3	2	$ 1.5	$ 3.3
Amounts reclassified from accumulated other comprehensive income (loss)	(1.2)	(1.3)
Net current period other comprehensive income (loss)	(1.2)	(1.3)
Settlement Cost [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	5	3.8
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	5	3.8
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Other Postretirement Benefit Plan [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	0	0
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefit Plan [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	$ 0	$ 0

Summary of Significant Accoun36

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ (0.4)	$ (4.4)	$ (6.1)	$ (5.3)
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]	(1.2)	(1)	(3.5)	(3.6)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Settlement Cost, before Tax	[1]	0	(6.2)	(8.2)	(6.2)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(1.2)	(7.2)	(11.7)	(9.8)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		(0.4)	(2.7)	(4.4)	(4.1)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(0.8)	(4.5)	(7.3)	(5.7)
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	(0.5)	0	(1.5)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	[1]	0.6	0.7	1.9	2.1
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		0.6	0.2	1.9	0.6
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		0.2	0.1	0.7	0.2
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ 0.4	$ 0.1	$ 1.2	$ 0.4
[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Summary of Significant Accoun37

Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Reclassifications (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
Prior Period Reclassification Adjustment	$ 1
Adjustments for New Accounting Pronouncement [Member]
Prior Period Reclassification Adjustment	$ 16.8

Investment in Unconsolidated 38

Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Apr. 30, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	May 13, 2014	May 01, 2013
Limited Partner Units Owned		111,000,000		111,000,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit				$ 0.31800
Equity in earnings of unconsolidated affiliates		$ 34.5	$ (71.9)	$ 79.5	$ (12)
percentage of subsidiary contributed							24.95%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		761.5		761.5		$ 783.5
Enogex LLC [Member]
Percentage of Enogex LLC Contributed								100.00%
Increase in fair value of net assets								$ 2,200
Enable Midstream Partners [Member]
Goodwill, Impairment Loss						$ 1,086.4
Partners' Capital Account, Units, Sold in Public Offering	25,000,000
Distributions from unconsolidated affiliates		$ 35.3	$ 35.1	$ 105.9	$ 104
CenterPoint [Member]
Percent of Incentive Distribution Rights		40.00%		40.00%
OGE Holdings [Member]
Subordinated Units Held by Limited Partners of the LLC or LP.				68,200,000
Percent of Incentive Distribution Rights		60.00%		60.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		26.30%	26.30%	26.30%	26.30%
OGE Energy [Member]
Goodwill, Impairment Loss		$ 0	$ (177.7)	$ 0.6	$ (177.7)

Investment in Unconsolidated 39

Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 2.4		$ 2.4		$ 1.7
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	3.7	$ 4.4	9	$ 11.1
Operating Costs Charged [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	1	2.6	3.6	7.9
Employment Costs [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	6.6	7	20.7	25.1
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	26.3
Natural Gas Purchases [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	4.4	$ 2.5	11.3	$ 7.1
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 3.7		$ 3.7		$ 3.4

Investment in Unconsolidated 40

Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 408	$ 381
Non-current assets	10,833	10,845
Current liabilities	338	615
Non-current liabilities	$ 3,174	$ 3,080

Investment in Unconsolidated 41

Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Schedule of Equity Method Investments [Line Items]
Operating revenues	$ 620	$ 646	$ 1,658	$ 1,852
Cost of natural gas and natural gas liquids	268	287	717	856
Operating income	139	(975)	299	(778)
Net income	$ 110.1	$ (985.1)	$ 230.8	$ (817.3)

Investment in Unconsolidated 42

Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Net income	$ 110.1	$ (985.1)	$ 230.8	$ (817.3)
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	761.5		761.5		$ 783.5
Timing Differences Related to Equity Method Investee Net Income	3	4.2	(3.6)	9.9
Net Income Used to Calculate Equity in Earnings	104	(980.9)	218.1	(807.4)
Proportionate Unconsolidated Affiliate Net Income	27.3	(257.2)	57.5	(212)
OGE Energy's share of Enable net income (loss)	27.3	(79.5)	58.1	(34.3)
Amortization of basis difference	(2.9)	(3.5)	8.8	(10.6)
Elimination of Enable fair value step up	(4.3)	(4.1)	12.6	(11.7)
Equity in earnings (loss) of unconsolidated affiliates	$ 34.5	$ (71.9)	$ 79.5	$ (12)
OGE Holdings [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	26.30%	26.30%	26.30%	26.30%
OGE Energy [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Goodwill, Impairment Loss	$ 0	$ (177.7)	$ 0.6	$ (177.7)
Preferred Partner [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ (9.1)	$ 0	$ (9.1)	$ 0

Fair Value Measurements Carryin

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 2,385	$ 2,493.9
Long-Term Debt, Fair Value	2,818.2	2,754.6
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	135.4	135.4
Long-Term Debt, Fair Value	135.4	135.4
OG&E Tinker Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	9.9	10
Long-Term Debt, Fair Value	10	9.2
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	99.8	99.5
Long-Term Debt, Fair Value	99.9	99.9
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Stock-Based Compensation Activity
Income tax benefit	$ 0	$ 0.5	$ 1.3	$ 2.3
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	(0.1)	1.1	3.1	6
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	(0.1)	1.1	3.2	6.1
Less: Amount paid by unconsolidated affiliates	0	(0.2)	0	0.3
Net compensation expense	(0.1)	1.3	3.2	5.8
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	1.2	1.9	3.4	5.7
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ (1.3)	$ (0.8)	$ (0.3)	$ 0.3

Common Equity Automatic Dividen

Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - shares	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, New Issues	0	0

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity [Abstract]
Net income	$ 183.6	$ 111.2	$ 280.3	$ 241.9
Basic average common shares outstanding	199.7	199.7	199.7	199.6
Contingently issuable shares (performance and restricted stock units)	0.2	0	0.1	0
Diluted average common shares outstanding	199.9	199.7	199.8	199.6
Earnings Per Share, Basic and Diluted [Abstract]
Basic Earnings Per Average Common Share	$ 0.92	$ 0.55	$ 1.40	$ 1.21
Diluted Earnings Per Average Common Share	$ 0.92	$ 0.55	$ 1.40	$ 1.21
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, 2016USD ($)
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
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
Minimum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.07%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.84%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.80%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.82%

Short-Term Debt and Credit Fa48

Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt		$ 213.2	$ 0
Line of Credit Facility [Abstract]
Aggregate Commitment		1,150
Amount Outstanding	[1]	$ 214.9
Weighted Average Interest Rate		0.74%
Intercompany Borrowing Agreement, Expiration Date		Dec. 13, 2017
OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[2]	$ 750
Amount Outstanding	[1],[2]	$ 213.2
Weighted Average Interest Rate	[2],[3]	0.74%
Maturity	[2],[4]	Dec. 13, 2018
OG&E [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[5]	$ 400
Letters of Credit Outstanding, Amount	[1],[5]	$ 1.7
Weighted Average Interest Rate	[3],[5]	0.95%
Maturity	[4],[5]	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
December 13, 2017 [Domain] | OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment		$ 16.3
December 13, 2017 [Domain] | OG&E [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment		$ 8.7
[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2016.
[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]	As of September 30, 2016, commitments of $16.3 million and $8.7 million of the OGE Energy's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.
[5]	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 Postreti49

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended				9 Months Ended
		Jul. 31, 2016	Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2016		Sep. 30, 2015
Pension Contributions		$ 20
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost (net of unconsolidated affiliates)			$ 3		$ 19.7		$ 17.8		$ 26.1
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			4		4.2		11.9		12.1
Interest cost			6.4		6.6		19.1		19.6
Expected return on plan assets			(10.4)		(11)		(31.1)		(34.5)
Amortization of net loss			4.1		3.8		12.3		13.5
Amortization of unrecognized prior service cost	[1]		(0.1)		0.1		(0.1)		0.3
Settlement			0		16.2		0		16.2
Total net periodic benefit cost			4		19.9		12.1		27.2
Less: Amount paid by unconsolidated affiliates			1.3		1		3.8		3.1
Net periodic benefit cost (net of unconsolidated affiliates)			2.7	[2]	18.9	[2]	8.3	[3]	24.1	[3]
Capitalized Portion of Net Periodic Benefit Cost			1		2.6		3		4.6
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			0		0.4		0.2		1
Interest cost			0.1		0.2		0.3		0.5
Expected return on plan assets			0		0		0		0
Amortization of net loss			0.2		0.2		0.5		0.5
Amortization of unrecognized prior service cost	[1]		0.1		0		0.1		0.1
Settlement			0		0		8.7		0
Total net periodic benefit cost			0.4		0.8		9.8		2.1
Less: Amount paid by unconsolidated affiliates			0.1		0		0.3		0.1
Net periodic benefit cost (net of unconsolidated affiliates)			0.3	[2]	0.8	[2]	9.5	[3]	2	[3]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements							(8.7)
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			0.2		0.4		0.6		1.2
Interest cost			2.4		2.6		7.1		7.7
Expected return on plan assets			(0.6)		(0.6)		(1.7)		(1.8)
Amortization of net loss			0.6		3.5		1.9		10.4
Amortization of unrecognized prior service cost	[4]		(2.1)		(4.1)		(6.5)		(12.4)
Total net periodic benefit cost			0.5		1.8		1.4		5.1
Less: Amount paid by unconsolidated affiliates			0		0.4		0.1		1
Net periodic benefit cost (net of unconsolidated affiliates)			0.5	[5]	1.4	[5]	1.3	[6]	4.1	[6]
Capitalized Portion of Net Periodic Benefit Cost			0.2		0.5		0.6		1.4
OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements			2.4		(4.7)		6.7		0.6
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements			1.9		1.4		5.9		4.3
ARKANSAS | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Settlement			$ 0		$ 1.4		$ 0.1		$ 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 $3.0 million and $19.7 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015, respectively, OG&E recognized the following:•an increase in pension expense during the three months ended September 30, 2016 of $2.4 million and a deferral of $4.7 million for the three months ended September 30, 2015, 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); and •during the three months ended September 30, 2016 there were no costs relating to the deferral of pension expense compared to $1.4 million for the three months ended September 30, 2015 related to the Arkansas jurisdictional portion of the pension settlement charge of $16.2 million during the three months ended September 30, 2015.
[3]	In addition to the $17.8 million and $26.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015, respectively, OG&E recognized the following: •an increase in pension expense during the nine months ended September 30, 2016 and 2015 of $6.7 million and $0.6 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); and•costs relating to the deferral of pension expense during the nine months ended September 30, 2016 and 2015 of $0.1 million and $1.4 million, respectively, related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million and $16.2 million, respectively.
[4]	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.
[5]	In addition to the $0.5 million and $1.4 million of net periodic benefit cost recognized during the three months ended September 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended September 30, 2016 and 2015 of $1.9 million and $1.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
[6]	In addition to the $1.3 million and $4.1 million of net periodic benefit cost recognized during the nine months ended September 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the nine months ended September 30, 2016 and 2015 of $5.9 million and $4.3 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).

Report of Business Segments (De

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 743.9	$ 719.8	$ 1,728.4	$ 1,749.8
Cost of sales	269.8	259.8	645.4	682.3
Other operation and maintenance	113.1	109.4	354.6	334.3
Depreciation and amortization	82.2	77.9	240.8	230
Taxes other than income	21.5	21.9	66.5	68.8
OPERATING INCOME	257.3	250.8	421.1	434.4
Equity in earnings of unconsolidated affiliates	34.5	(71.9)	79.5	(12)
Other income	6.3	5.8	17.3	16.3
Interest expense	35.4	37	107.7	112.4
Income tax expense (benefit)	79.1	36.5	129.9	84.4
Net income	183.6	111.2	280.3	241.9
Investment in unconsolidated affiliates	1,168	1,202.2	1,168	1,202.2	$ 1,194.4
Total assets	9,784	9,600.7	9,784	9,600.7	$ 9,580.6
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	743.9	719.8	1,728.4	1,749.8
Cost of sales	269.8	259.8	645.4	682.3
Other operation and maintenance	115.2	107.4	356.3	337.3
Depreciation and amortization	80.8	75.9	235.9	224
Taxes other than income	20.9	21	63.6	65.7
OPERATING INCOME	257.2	255.7	427.2	440.5
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income	6	6.6	18.3	13.9
Interest expense	34.3	36.4	104.8	110.5
Income tax expense (benefit)	69	63	102.4	94.9
Net income	159.9	162.9	238.3	249
Investment in unconsolidated affiliates	0	0	0	0
Total assets	8,511.5	8,554.1	8,511.5	8,554.1
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	(0.1)	4.9	7.9	5.9
Depreciation and amortization	0	0	0	0
Taxes other than income	0	0	0	0
OPERATING INCOME	0.1	(4.9)	(7.9)	(5.9)
Equity in earnings of unconsolidated affiliates	34.5	(71.9)	79.5	(12)
Other income	0	0	0	0
Interest expense	0	0	0	0
Income tax expense (benefit)	12.1	(26.8)	31.5	(8.7)
Net income	22.5	(50)	40.1	(9.2)
Investment in unconsolidated affiliates	1,168	1,202.2	1,168	1,202.2
Total assets	1,503.1	1,541.5	1,503.1	1,541.5
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)	(2.9)	(9.6)	(8.9)
Depreciation and amortization	1.4	2	4.9	6
Taxes other than income	0.6	0.9	2.9	3.1
OPERATING INCOME	0	0	1.8	(0.2)
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income	0.3	(0.7)	(0.8)	2.6
Interest expense	1.1	0.7	3.1	2.1
Income tax expense (benefit)	(2)	0.3	(4)	(1.8)
Net income	1.2	(1.7)	1.9	2.1
Investment in unconsolidated affiliates	0	0	0	0
Total assets	93.3	133.5	93.3	133.5
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	0	0	0	0
Other income	0	(0.1)	(0.2)	(0.2)
Interest expense	0	(0.1)	(0.2)	(0.2)
Income tax expense (benefit)	0	0	0	0
Net income	0	0	0	0
Investment in unconsolidated affiliates	0	0	0	0
Total assets	(323.9)	(628.4)	(323.9)	(628.4)
OGE Energy [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss	$ 0	$ (177.7)	$ 0.6	(177.7)
Impairment Adjusted for Basis Difference [Member] | OGE Energy [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss				$ 108.4

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, 2016	Dec. 31, 2015	Dec. 31, 2013
Annual Recovery of Lost Revenues Through Rate Implementation	$ 10
Additional Requested Plant Dismantlement Cost	$ 8
Change in Requested Return on Equity	0.25%
Change in Requested Rate Increase	$ 9
SmartHours Program [Member]
Lost Revenue Associated with Customer Programs	36.6	$ 30.3	$ 10.1
Dry Scrubber Project [Member]
Estimated Environmental Capital Costs	547.5
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	138.6
Mustang Modernization [Member]
Estimated Environmental Capital Costs	424.9
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	133.6
OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 92.5
Public Utilities, Requested Return on Equity, Percentage	10.25%
Public Utilities, Requested Equity Capital Structure, Percentage	53.00%
Investments Since Last Rate Case		1,600
Public Utilities, Interim Rate Increase (Decrease), Amount	$ 69.5
Interim Rate Collected	23.6
Interim Rate Revenue Reserved	21
ARKANSAS
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 16.5
Public Utilities, Requested Return on Equity, Percentage	10.25%
Investments Since Last Rate Case		$ 3,000
Oklahoma Attorney General [Member]
Reduction to Requested Additional Plant Dismantlement Costs	$ 20.9
Oklahoma Public Utility Division Staff [Member]
Recommended Return on Equity	9.25%
Recommended Common Equity Percentage	53.00%
Reduction to Requested Additional Plant Dismantlement Costs	$ 33
Recommended Rate Increase (Decrease)	$ 6.1
Oklahoma Industrial Electric Consumers [Member]
Recommended Return on Equity	9.00%
Recommended Common Equity Percentage	53.00%
Reduction to Requested Additional Plant Dismantlement Costs	$ 52.5
Recommended Rate Increase (Decrease)	$ 47.9
Recommendation 1 [Member] | Oklahoma Attorney General [Member]
Recommended Return on Equity	9.25%
Recommended Common Equity Percentage	50.00%
Recommended Rate Increase (Decrease)	$ 10.8
Recommendation 2 [Member] | Oklahoma Attorney General [Member]
Recommended Return on Equity	8.90%
Recommended Common Equity Percentage	53.00%
Recommended Rate Increase (Decrease)	$ 13.7
Change in Allowed Amount [Member] | SmartHours Program [Member]
Lost Revenue Associated with Customer Programs	$ (6.3)