OGE Energy (OGE) 10-Q 9 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document	6 Months Ended
	Jun. 30, 2018shares
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	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,731,036

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues from contracts with customers	$ 547.7	$ 0	$ 1,025.6	$ 0
Other revenues	19.3	0	34.1	0
Operating revenues	567	586.4	1,059.7	1,042.4
COST OF SALES	208.7	232.1	419.2	440.8
OPERATING EXPENSES
Other operation and maintenance	123.2	112.5	242	234.6
Depreciation and amortization	80.9	74.7	159.7	130.3
Taxes other than income	22.5	21.3	46.6	45.2
Operating expenses	226.6	208.5	448.3	410.1
OPERATING INCOME	131.7	145.8	192.2	191.5
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	29.3	29.4	63.2	65
Allowance for equity funds used during construction	6.3	8.5	13.3	15.4
Other net periodic benefit income (expense)	0.8	(2.3)	2.1	(4.2)
Other income	4.7	10.3	10.1	19.1
Other expense	(3.3)	(3.2)	(7.7)	(7.3)
Net other income	37.8	42.7	81	88
INTEREST EXPENSE
Interest on long-term debt	39.7	39.2	79.3	75.1
Allowance for borrowed funds used during construction	(2.8)	(4.1)	(6.5)	(7.4)
Interest on short-term debt and other interest charges	4	2	6.7	4.4
Interest expense	40.9	37.1	79.5	72.1
INCOME BEFORE TAXES	128.6	151.4	193.7	207.4
INCOME TAX EXPENSE	17.9	46.6	28	66.6
NET INCOME	$ 110.7	$ 104.8	$ 165.7	$ 140.8
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7	199.7	199.7	199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.5	199.9	200.3	200
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.55	$ 0.52	$ 0.83	$ 0.70
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.55	0.52	0.83	0.70
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.33250	$ 0.30250	$ 0.66500	$ 0.60500

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net income	$ 110.7	$ 104.8	$ 165.7	$ 140.8
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.3, $0.4, $0.5 and $0.8, respectively	1	0.8	1.7	1.4
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.2), ($0.0), ($0.3) and ($0.0), respectively	(0.3)	0	(0.8)	0
Other comprehensive income, net of tax	0.7	0.8	0.9	1.4
Comprehensive income	$ 111.4	$ 105.6	$ 166.6	$ 142.2

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.3	$ 0.4	$ 0.5	$ 0.8
Postretirement Benefit Plans:
Amortization of prior service cost	$ (0.2)	$ 0	$ (0.3)	$ 0

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 165.7	$ 140.8
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	159.7	130.3
Deferred income taxes and investment tax credits, net	19.4	68
Equity in earnings of unconsolidated affiliates	(63.2)	(65)
Distributions from unconsolidated affiliates	63.2	65
Allowance for equity funds used during construction	(13.3)	(15.4)
Stock-based compensation expense	5.8	4.5
Regulatory assets	(1.6)	(15.6)
Regulatory liabilities	1.9	(0.2)
Other assets	(7.3)	3.5
Other liabilities	(0.6)	11.7
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(51.5)	(38.6)
Income taxes receivable	(2)	4.6
Fuel, materials and supplies inventories	0.1	1.1
Fuel recoveries	37	(56.1)
Other current assets	22	5.7
Accounts payable	(45.7)	1.3
Other current liabilities	50	(41.2)
Net cash provided from operating activities	354.2	197.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(273.8)	(491.1)
Investment in unconsolidated affiliates	(0.5)	(5.2)
Return of capital - unconsolidated affiliates	7.4	5.6
Proceeds from sale of assets	0	0.4
Net cash used in investing activities	(266.9)	(490.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt	31.7	(43)
Proceeds from long-term debt	0	296.5
Payment of long-term debt	0	(0.1)
Increase in long-term revolver	0	160
Dividends paid on common stock	(133)	(120.8)
Other	(0.4)	0
Net cash (used in) provided from financing activities	(101.7)	292.6
NET CHANGE IN CASH AND CASH EQUIVALENTS	(14.4)	(0.3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	14.4	0.3
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 0	$ 14.4
Accounts receivable, less reserve of $1.0 and $1.5, respectively	221.2	188.7
Accounts receivable - unconsolidated affiliates	0	1.9
Accrued unbilled revenues	87.8	66.5
Income taxes receivable	7.8	5.8
Fuel inventories	81.1	84.3
Materials and supplies, at average cost	130.3	80.8
Other	32.6	54.6
Total current assets	560.8	497
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,153.6	1,160.4
Other	77	76.7
Total other property and investments	1,230.6	1,237.1
PROPERTY, PLANT AND EQUIPMENT
In service	11,544.6	11,041.2
Construction work in progress	566	867.5
Total property, plant and equipment	12,110.6	11,908.7
Less accumulated depreciation	3,637.5	3,568.8
Net property, plant and equipment	8,473.1	8,339.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	270.2	283
Other	8.9	55.7
Total deferred charges and other assets	279.1	338.7
TOTAL ASSETS	10,543.6	10,412.7
CURRENT LIABILITIES
Short-term debt	200.1	168.4
Accounts payable	161.4	230.4
Dividends payable	66.4	66.4
Customer deposits	82.5	80.7
Accrued taxes	42.9	44.5
Accrued interest	44	44
Accrued compensation	37.7	35.9
Long-term debt due within one year	499.9	249.8
Fuel clause over recoveries	38.7	1.7
Other	76.7	28.7
Total current liabilities	1,250.3	950.5
LONG-TERM DEBT	2,500.4	2,749.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	188.4	192.7
Deferred income taxes	1,255.1	1,227.8
Regulatory liabilities	1,296.1	1,283.4
Other	163.2	157.6
Total deferred credits and other liabilities	2,902.8	2,861.5
Total liabilities	6,653.5	6,561.6
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,120.1	1,114.8
Retained earnings	2,792.3	2,759.5
Accumulated other comprehensive loss, net of tax	(22.3)	(23.2)
Total stockholders' equity	3,890.1	3,851.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 10,543.6	$ 10,412.7

CONDENSED CONSOLIDATED BALANCE7

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Allowance for Doubtful Accounts Receivable	$ 1	$ 1.5

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Unaudited) - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Common Stock, Shares, Outstanding		199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Balance at Dec. 31, 2016	$ 3,443.8	$ 2	$ 1,103.8	$ 2,367.3	$ (29.3)
Changes in Stockholders' Equity
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Net income	140.8	$ 0	0	140.8	0
Dividends, Common Stock, Cash, Number of Shares		0
Other comprehensive income, net of tax	1.4	$ 0	0	0	1.4
Dividends declared on common stock	(120.8)	$ 0	0	(120.8)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	22.3	$ 0	0	22.3	0
Accounting Pronouncement or Change in Accounting Principal, effect of Adoption, Quantification, number of shares		0
Stock-based compensation	4.5	$ 0	4.5	0	0
Balance at Jun. 30, 2017	3,492	$ 2	1,108.3	2,409.6	(27.9)
Common Stock, Shares, Outstanding		199.7
Common Stock, Shares, Outstanding		199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Balance at Dec. 31, 2017	3,851.1	$ 2	1,112.8	2,759.5	(23.2)
Changes in Stockholders' Equity
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Net income	165.7	$ 0	0	165.7	0
Dividends, Common Stock, Cash, Number of Shares		0
Other comprehensive income, net of tax	0.9	$ 0	0	0	0.9
Dividends declared on common stock	(132.9)	$ 0	0	(132.9)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
Stock-based compensation	5.3	$ 0	5.3	0	0
Balance at Jun. 30, 2018	$ 3,890.1	$ 2	$ 1,118.1	$ 2,792.3	$ (22.3)
Common Stock, Shares, Outstanding		199.7

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Significant Accounting Policies [Text Block]	Summary of Significant Accounting Policies The Company's significant accounting policies are detailed in "Note 1. Summary of Significant Accounting Policies" in the Company's 2017 Form 10-K. Changes to the Company's accounting policies as a result of adopting ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," are discussed in Note 3 in this Form 10-Q.
Organization, Consolidation and Presentation of Financial Statements Disclosure [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 U.S. 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 it 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 wholly owned subsidiaries and ultimately 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 the Company and CenterPoint, 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 [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 June 30, 2018 and December 31, 2017 , the consolidated results of its operations for the three and six months ended June 30, 2018 and 2017 and its consolidated cash flows for the six months ended June 30, 2018 and 2017 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after June 30, 2018 up to the date of issuance of these Condensed Consolidated Financial Statements, and these statements contain all necessary adjustments and disclosures resulting from that evaluation. Due to seasonal fluctuations and other factors , the Company's operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 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 2017 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. June 30, December 31, (In millions) 2018 2017 REGULATORY ASSETS Current: Oklahoma demand program rider under recovery (A) $ 16.7 $ 31.6 SPP cost tracker under recovery (A) 0.8 7.7 Other (A) 2.2 1.5 Total current regulatory assets $ 19.7 $ 40.8 Non-current: Benefit obligations regulatory asset $ 171.9 $ 177.2 Deferred storm expenses 39.0 42.2 Smart Grid 29.3 32.8 Unamortized loss on reacquired debt 11.8 12.3 Other 18.2 18.5 Total non-current regulatory assets $ 270.2 $ 283.0 REGULATORY LIABILITIES Current: Fuel clause over recoveries $ 38.7 $ 1.7 Other (B) 2.5 2.2 Total current regulatory liabilities $ 41.2 $ 3.9 Non-current: Income taxes refundable to customers, net $ 944.2 $ 955.5 Accrued removal obligations, net 300.2 288.4 Pension tracker 44.4 32.3 Other 7.3 7.2 Total non-current regulatory liabilities $ 1,296.1 $ 1,283.4 (A) Included in Other Current Assets on the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects.
Comprehensive Income (Loss) Note [Text Block]	Accumulated Other Comprehensive Income (Loss) The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months ended June 30, 2018 and 2017 . All amounts below are presented net of tax. Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service credit Total Balance at December 31, 2017 $ (32.7 ) $ — $ 2.5 $ 7.0 $ (23.2 ) Amounts reclassified from accumulated other comprehensive income (loss) 1.7 — — (0.8 ) 0.9 Balance at June 30, 2018 $ (31.0 ) $ — $ 2.5 $ 6.2 $ (22.3 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service credit Total Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) Amounts reclassified from accumulated other comprehensive income 1.4 — — — 1.4 Balance at June 30, 2017 $ (30.7 ) $ 0.1 $ 2.7 $ — $ (27.9 ) 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 six months ended June 30, 2018 and 2017 . Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Condensed Consolidated Statements of Income Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Amortization of Pension Plan and Restoration of Retirement Income Plan items: Actuarial losses (A) $ (1.3 ) $ (1.2 ) $ (2.2 ) $ (2.2 ) Other Net Periodic Benefit Income (Expense) (0.3 ) (0.4 ) (0.5 ) (0.8 ) Income Tax Expense $ (1.0 ) $ (0.8 ) $ (1.7 ) $ (1.4 ) Net Income Amortization of postretirement benefit plans items: Prior service credit (A) $ 0.5 $ — $ 1.1 $ — Other Net Periodic Benefit Income (Expense) 0.2 — 0.3 — Income Tax Expense $ 0.3 $ — $ 0.8 $ — Net Income Total reclassifications for the period, net of tax $ (0.7 ) $ (0.8 ) $ (0.9 ) $ (1.4 ) Net Income (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).
Reclassifications [Text Block]	Reclassifications Certain prior-year amounts have been reclassified to conform to the current year presentation. Amounts for the three and six months ended June 30, 2017 have been adjusted for the reclassification of net periodic benefit cost components between Other Operation and Maintenance and Other Net Periodic Benefit Income (Expense) on the Company's Condensed Consolidated Statements of Income to be consistent with the 2018 presentation due to the Company's adoption of ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost."

Accounting Pronouncements

Accounting Pronouncements	6 Months Ended
	Jun. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting Pronouncements Recently Adopted Accounting Standards Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The Company adopted this standard in the first quarter of 2018 utilizing the modified retrospective transition method and applied the new standard only to contracts that were not completed at the date of initial application. The Company determined it was not necessary to change the timing or amounts of revenue recognized based on the adoption of Topic 606. Therefore, financial statement amounts in the period of adoption have not changed under Topic 606 as compared with the guidance that was in effect before the adoption of Topic 606. The adoption did change financial statement presentation as Operating Revenues are now separated between Revenues from Contracts with Customers and Other Revenues on the 2018 Condensed Consolidated Statement of Income. In addition, gains and losses associated with OG&E's guaranteed flat bill program that were previously included in Net Other Income on the Condensed Consolidated Statements of Income are now presented as Revenues from Contracts with Customers since the gains and losses are included within the transaction price in the contract under Topic 606. Operating Revenues presented on the 2017 Condensed Consolidated Statement of Income did not change from prior year. Alternative revenue programs are scoped out of Topic 606, as these programs are considered agreements between an entity and a regulator, not contracts between an entity and a customer; therefore, the Company now presents revenues from alternative revenue programs separately from revenues from contracts with customers. Further discussion regarding the Company's revenue recognition as well as additional disclosures resulting from the adoption of Topic 606 can be found in Note 3. Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. In February 2017, the FASB issued ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets." ASC 610-20 was issued as part of ASU 2014-09 and was added to provide guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with non-customers. The new guidance clarifies the application of the guidance in Topic 606 for the derecognition of nonfinancial assets and unifies guidance related to partial sales of nonfinancial assets. The Company adopted the new guidance beginning in the first quarter of 2018, which did not have a material effect on its Condensed Consolidated Financial Statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit cost between those that are attributed to compensation for service and those that are not. The service cost component of benefit cost continues to be presented within operating income, but entities are now required to present the other components of benefit cost as non-operating within the income statement. Additionally, the new guidance only permits the capitalization of the service cost component of net benefit cost. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs. The Company adopted the new guidance beginning in the first quarter of 2018. The presentation and recognition impacts of the Company's adoption of ASU 2017-07 are further discussed in Note 11. Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The new guidance, among other things, requires entities to measure equity instruments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) at fair value with changes in fair value recognized in net income. Further, an entity has the option to measure equity instruments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investment of the same issuer. The Company adopted the new guidance beginning in the first quarter of 2018, which did not have a material effect on its Condensed Consolidated Financial Statements. Issued Accounting Standards Not Yet Adopted 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-of-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, 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 method and provides for certain practical expedients. Transition method options include application of the new guidance at the beginning of the earliest comparative period presented or at the adoption date, with a cumulative-effect adjustment to retained earnings in the period of adoption. The Company is evaluating its current lease contracts and currently intends to take the package of practical expedients allowing entities to not reassess (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases and (iii) initial direct costs for any existing leases. The Company has not quantified the impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities. In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842," which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that exist or expired before the entity's adoption of Topic 842 and that were not previously accounted for as leases under ASC 840, "Leases." Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 2018. The Company currently intends to elect this practical expedient during its adoption of Topic 842 and does not plan to evaluate existing easement contracts under Topic 842, if these contracts have not previously been accounted for under Topic 840. In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which provides the following additional amendments to ASU 2016-02: (i) entities can elect to initially apply ASU 2016-02 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and (ii) lessors can elect a practical expedient, by class of underlying asset, to account for nonlease components and the associated lease component as a single component, if the nonlease component otherwise would be accounted for under Topic 606 and certain conditions, as described in ASU 2018-11, are met. If an entity elects the additional (and optional) transition method, the entity will provide the required Topic 840 disclosures for all periods that continue to be reported under Topic 840. ASU 2018-11 is effective for fiscal years beginning after December 2018. The Company is reviewing potential impacts of ASU 2018-11 and currently intends to elect the transition method provided by the guidance allowing for initial application at the adoption date.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenue Recognition Revenue from Contracts with Customers General OG&E recognizes revenue from electric sales when power is delivered to customers. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Condensed Consolidated Balance Sheets and in Revenues from Contracts with Customers on the Condensed Consolidated Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers. Integrated Market and Transmission OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. Sales are billed based on the fixed transaction price determined by the market at the time of the sale and the MWh quantity purchased. These results are reported as Revenues from Contracts with Customers or Cost of Sales in the Condensed Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP. OG&E's transmission revenues are generated by the use of OG&E's transmission network by the SPP, which operates the network, on behalf of other transmission owners. OG&E recognizes revenue on the sale of transmission service to its customers over time as the service is provided in the amount OG&E has a right to invoice. Transmission service to the SPP is billed monthly based on a fixed transaction price determined by OG&E's FERC-approved formula transmission rates along with other SPP-specific charges and the megawatt quantity reserved. Disaggregated Revenue The following table disaggregates the Company's revenues from contracts with customers by customer classification. The Company's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations." June 30, 2018 (In millions) Three Months Ended Six Months Ended Residential $ 217.3 $ 413.5 Commercial 152.4 270.2 Industrial 47.7 89.4 Oilfield 37.7 71.5 Public authorities and street light 51.1 92.8 System sales revenues 506.2 937.4 Provision for rate refund (16.5 ) (19.7 ) Integrated market 13.1 21.8 Transmission 40.2 76.0 Other 4.7 10.1 Revenues from contracts with customers $ 547.7 $ 1,025.6 Other Revenues Revenues from Alternative Revenue Programs Other Revenues on the Condensed Consolidated Statements of Income is comprised of certain rider revenue that includes alternative revenue measures as defined in ASC 980, "Regulated Operations," which details two types of alternative revenue programs. The first type adjusts billings for the effects of weather abnormalities or broad external factors or to compensate OG&E for demand-side management initiatives (i.e., no-growth plans and similar conservation efforts). The second type provides for additional billings (i.e., incentive awards) for the achievement of certain objectives, such as reducing costs, reaching specified milestones or demonstratively improving customer service. Once the specific events permitting billing of the additional revenues under either program type have been completed, OG&E recognizes the additional revenues if (i) the program is established by an order from OG&E's regulatory commission that allows for automatic adjustment of future rates; (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery; and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	Investment in Unconsolidated Affiliates 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; therefore, 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 at June 30, 2018 as presented in Note 12. 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 Affiliates 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. Enable completed an initial public offering resulting in Enable becoming a publicly traded Master Limited Partnership in April 2014. At June 30, 2018 , the Company owned 111.0 million common units, or 25.6 percent , of Enable's outstanding common units. Distributions received from Enable were $35.3 million during both the three months ended June 30, 2018 and 2017 and $70.6 million during both the six months ended June 30, 2018 and 2017 . On August 1, 2018, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable's cash distributions at the time of the exercise of this reset election. Related Party Transactions The Company and Enable are currently parties to several agreements whereby the Company provides specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $0.2 million and $0.7 million for the three months ended June 30, 2018 and 2017 , respectively, and $0.3 million and $1.5 million for the six months ended June 30, 2018 and 2017 , respectively. The Company charges operating costs to OG&E and Enable based on several factors, and 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, which is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of June 30, 2018 , 134 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $5.2 million and $7.3 million during the three months ended June 30, 2018 and 2017 , respectively, and $16.8 million and $17.3 million for the six months ended June 30, 2018 and 2017 , respectively, under the seconding agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $13.8 million . Settlement and curtailment charges associated with the seconded employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 days' notice. The Company had accounts receivable from Enable for amounts billed for support services, including the cost of seconded employees, of $1.8 million as of June 30, 2018 and $2.0 million as of December 31, 2017 . Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. 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 six months ended June 30, 2018 and 2017 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Operating revenues: Electricity to power electric compression assets $ 3.6 $ 3.3 $ 7.6 $ 5.5 Cost of sales: Natural gas transportation services $ 8.8 $ 8.8 $ 17.5 $ 17.5 Natural gas purchases (sales) $ 2.2 $ (0.4 ) $ 2.5 $ (0.8 ) Summarized Financial Information of Enable Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2018 and December 31, 2017 and for the three and six months ended June 30, 2018 and 2017 . June 30, December 31, Balance Sheet 2018 2017 (In millions) Current assets $ 432 $ 416 Non-current assets $ 11,360 $ 11,177 Current liabilities $ 1,258 $ 1,279 Non-current liabilities $ 2,963 $ 2,660 Three Months Ended Six Months Ended June 30, June 30, Income Statement 2018 2017 2018 2017 (In millions) Operating revenues $ 805 $ 626 $ 1,553 $ 1,292 Cost of natural gas and NGLs $ 444 $ 279 $ 819 $ 587 Operating income $ 126 $ 122 $ 265 $ 262 Net income $ 86 $ 86 $ 191 $ 197 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 $29.3 million and $29.4 million for the three months ended June 30, 2018 and 2017 , respectively, and $63.2 million and $65.0 million for the six months ended June 30, 2018 and 2017 , 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 LLC and its underlying equity in the net assets of Enable. The basis difference is being amortized over approximately 30 years, which is the average life of the assets to which the basis difference is attributed, beginning in May 2013. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments , as described below. The following table reconciles the Company's equity in earnings of unconsolidated affiliates for the three and six months ended June 30, 2018 and 2017 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Enable net income $ 86.4 $ 86.2 $ 191.0 $ 197.4 OGE Energy's percent ownership at period end 25.6 % 25.7 % 25.6 % 25.7 % OGE Energy's portion of Enable net income 22.2 22.2 49.0 50.7 Amortization of basis difference 2.8 2.9 5.6 5.7 Elimination of Enable fair value step up 4.3 4.3 8.6 8.6 Equity in earnings of unconsolidated affiliates $ 29.3 $ 29.4 $ 63.2 $ 65.0 The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $696.9 million as of June 30, 2018 . The following table reconciles the basis difference in Enable from December 31, 2017 to June 30, 2018 . (In millions) Basis difference at December 31, 2017 $ 714.2 Change in Enable basis difference (3.1 ) Amortization of basis difference (5.6 ) Elimination of Enable fair value step up (8.6 ) Basis difference at June 30, 2018 $ 696.9

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2018
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 June 30, 2018 and December 31, 2017 . 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 is classified as Level 3 in the fair value hierarchy as its fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate. The following table summarizes the fair value and carrying amount of the Company's financial instruments at June 30, 2018 and December 31, 2017 . June 30, December 31, 2018 2017 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year): Senior Notes $ 2,855.2 $ 3,101.4 $ 2,854.3 $ 3,242.8 OG&E Industrial Authority Bonds $ 135.4 $ 135.4 $ 135.4 $ 135.4 Tinker Debt $ 9.7 $ 9.1 $ 9.7 $ 9.8

Stock-Based Compensation

Stock-Based Compensation	6 Months Ended
	Jun. 30, 2018
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 six months ended June 30, 2018 and 2017 related to the Company's performance units and restricted stock . Three Months Ended June 30, Six Months Ended June 30, (In millions) 2018 2017 2018 2017 Performance units: Total shareholder return $ 2.1 $ 1.8 $ 4.1 $ 3.3 Earnings per share 1.0 0.6 1.7 1.2 Total performance units 3.1 2.4 5.8 4.5 Restricted stock — — — — Total compensation expense $ 3.1 $ 2.4 $ 5.8 $ 4.5 Income tax benefit $ 0.8 $ 1.0 $ 1.5 $ 1.8 During the three and six months ended June 30, 2018 , the Company issued an immaterial number of shares of new common stock pursuant to the Company's Stock Incentive Plan to satisfy restricted stock grants and payouts of earned performance units.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes As previously discussed in the Company's 2017 Form 10-K, the 2017 Tax Act was signed into law in December 2017, reducing the corporate federal tax rate from 35 percent to 21 percent for tax years beginning in 2018. ASC 740, "Income Taxes," requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized and settled. Entities subject to ASC 980, "Accounting for Regulated Entities," such as OG&E, are required to recognize a regulatory liability for the decrease in taxes payable for the change in tax rates that are expected to be returned to customers through future rates and to recognize a regulatory asset for the increase in taxes receivable for the change in tax rates that are expected to be recovered from customers through future rates. At December 31, 2017 , as a result of remeasuring existing deferred taxes at the lower 21 percent tax rate, the Company reduced net deferred income tax liabilities and increased regulatory liabilities. As of June 30, 2018 , the Company's regulatory liability for income taxes refundable to customers, net was $1.028 billion , as a result of the change in the corporate federal tax rate. Staff Accounting Bulletin No. 118 addresses the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the 2017 Tax Act. The Company recognized the provisional tax impacts related to the revaluation of deferred tax assets and liabilities as of December 31, 2017. The ultimate impact may differ from those provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions the Company has made, additional regulatory guidance that may be issued and the actions the Company may take as a result of the 2017 Tax Act. The Company continues to evaluate its computations, and any subsequent adjustments to the amounts recognized as of December 31, 2017 will be recorded in the quarter when the analysis is complete. As a result of the 2017 Tax Act, in early January 2018: (i) the OCC ordered OG&E to record a reserve, including accrued interest, to reflect the reduced federal corporate tax rate, among other tax implications, on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings; (ii) the APSC ordered OG&E to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act until the resulting benefits, including carrying charges, are returned to customers; and (iii) through a Section 206 filing with the FERC, modifications were requested to be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act. For Oklahoma jurisdictional revenues, OG&E has reserved the excess income taxes collected in current rates, plus interest, from January 2018 to June 2018, which was refunded to Oklahoma customers, as approved by the OCC, during the July 2018 billing cycle. For Arkansas jurisdictional revenues, OG&E is reserving the excess income taxes collected in current rates, plus carrying charges, from January 2018 to the effective date of the rider based on an order received from the APSC. For FERC jurisdictional revenues, OG&E is reserving the excess income taxes collected in current rates, plus interest, from January 2018 to the date the new tax rate is reflected in billings based on an order received from the FERC. Further, for Oklahoma, Arkansas and FERC jurisdictional revenues, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act. As of June 30, 2018 , the total recorded reserve was $32.8 million , which is included in Other Current Liabilities on the Company's Condensed Consolidated Balance Sheets. Further discussion can be found in Note 14. 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 2014 or state and local tax examinations by tax authorities for years prior to 2013 . 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	6 Months Ended
	Jun. 30, 2018
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 six months ended June 30, 2018 . 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. The following table calculates basic and diluted earnings per share for the Company. Three Months Ended June 30, Six Months Ended June 30, (In millions except per share data) 2018 2017 2018 2017 Net income $ 110.7 $ 104.8 $ 165.7 $ 140.8 Average common shares outstanding: Basic average common shares outstanding 199.7 199.7 199.7 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.8 0.2 0.6 0.3 Diluted average common shares outstanding 200.5 199.9 200.3 200.0 Basic earnings per average common share $ 0.55 $ 0.52 $ 0.83 $ 0.70 Diluted earnings per average common share $ 0.55 $ 0.52 $ 0.83 $ 0.70 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2018
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	Long-Term Debt At June 30, 2018 , 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 included in the following table. SERIES DATE DUE AMOUNT (In millions) 1.06% - 2.00% Garfield Industrial Authority, January 1, 2025 $ 47.0 1.05% - 1.83% Muskogee Industrial Authority, January 1, 2025 32.4 1.06% - 1.86% 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	6 Months Ended
	Jun. 30, 2018
Short-term Debt [Abstract]
Short-Term Debt and Credit Facilities	Short-Term Debt and Credit Facilities The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. As of June 30, 2018 , the Company had $200.1 million of short-term debt as compared to $168.4 million at December 31, 2017 . The following table provides information regarding the Company's revolving credit agreements at June 30, 2018 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ 200.1 2.31 % (D) March 8, 2023 (E) OG&E (C) 450.0 0.3 0.95 % (D) March 8, 2023 (E) Total $ 900.0 $ 200.4 2.31 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2018 . (B) This bank facility is available to back up the Company'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) In March 2017, the Company and OG&E entered into unsecured five-year revolving credit agreements totaling $900.0 million ( $450.0 million for the Company and $450.0 million for OG&E). Each of the facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. Effective March 9, 2018, the Company and OG&E utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023. 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, 2017 and ending December 31, 2018.

Retirement Plans and Postretire

Retirement Plans and Postretirement Benefit Plans	6 Months Ended
	Jun. 30, 2018
Defined Benefit Plan [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Retirement Plans and Postretirement Benefit Plans Net Periodic Benefit Cost The Company adopted ASU 2017-07 in the first quarter of 2018 and, as a result, presents the service cost component of net benefit cost in operating income and the other components of net benefit cost as non-operating within its Condensed Consolidated Statements of Income. Further, as required by ASU 2017-07, the Company adjusted prior year income statement presentation of the net benefit cost components, which were previously presented in total within Other Operation and Maintenance on the Company's Condensed Consolidated Statements of Income. The Company elected the practical expedient allowed by ASU 2017-07 to utilize amounts disclosed in the Company's retirement plans and postretirement benefit plans note for the prior comparative period as the estimation basis for applying the retrospective presentation requirements. The following tables present the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Condensed Consolidated Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss and amortization of unrecognized prior service cost are presented within Other Net Periodic Benefit Income (Expense) on the Company's Condensed Consolidated Statements of Income. Pension Plan Restoration of Retirement Three Months Ended Six Months Ended Three Months Ended Six Months Ended June 30, June 30, June 30, June 30, (In millions) 2018 2017 2018 2017 2018 2017 2018 2017 Service cost $ 3.4 $ 3.5 $ 7.5 $ 7.7 $ 0.1 $ 0.1 $ 0.2 $ 0.2 Interest cost 5.8 6.6 11.7 13.1 0.1 — 0.2 0.1 Expected return on plan assets (11.0 ) (10.6 ) (22.3 ) (21.3 ) — — — — Amortization of net loss 4.4 4.7 8.3 8.7 0.3 0.1 0.4 0.2 Total net periodic benefit cost 2.6 4.2 5.2 8.2 0.5 0.2 0.8 0.5 Less: Amount paid by unconsolidated affiliates 0.7 0.9 1.2 1.7 — — — — Net periodic benefit cost $ 1.9 $ 3.3 $ 4.0 $ 6.5 $ 0.5 $ 0.2 $ 0.8 $ 0.5 (A) In addition to the $2.4 million and $3.5 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017 , respectively , the Company recognized the following: • an increase in pension expense during the three months ended June 30, 2018 and 2017 of $3.8 million and $2.9 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1) ; and • a deferral of pension expense during the three months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013. (B) In addition to the $4.8 million and $7.0 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017 , respectively, the Company recognized the following: • an increase in pension expense during the six months ended June 30, 2018 and 2017 of $7.8 million and $5.8 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the six months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013. Postretirement Benefit Plans Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 (B) 2017 (B) 2018 (C) 2017 (C) Service cost $ 0.1 $ 0.2 $ 0.2 $ 0.4 Interest cost 1.3 2.1 2.6 4.3 Expected return on plan assets (0.5 ) (0.5 ) (1.0 ) (1.1 ) Amortization of net loss 0.9 0.2 1.9 0.8 Amortization of unrecognized prior service cost (A) (2.1 ) — (4.2 ) — Total net periodic benefit cost (0.3 ) 2.0 (0.5 ) 4.4 Less: Amount paid by unconsolidated affiliates (0.1 ) 0.2 (0.2 ) 0.6 Net periodic benefit cost $ (0.2 ) $ 1.8 $ (0.3 ) $ 3.8 (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 $0.2 million of net periodic benefit income and $1.8 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017 , respectively, the Company recognized an increase in postretirement medical expense in the three months ended June 30, 2018 and 2017 of $2.2 million and $1.0 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 $0.3 million of net periodic benefit income and $3.8 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017 , respectively, the Company recognized an increase in postretirement medical expense in the six months ended June 30, 2018 and 2017 of $4.3 million and $2.1 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). As required by ASU 2017-07, the Company only capitalizes the service cost component of net benefit cost, beginning in the first quarter of 2018. Prior year capitalized amounts were not adjusted, as this change was implemented on a prospective basis. Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Capitalized portion of net periodic pension benefit cost $ 0.9 $ 1.2 $ 1.9 $ 2.3 Capitalized portion of net periodic postretirement benefit cost $ 0.1 $ 0.5 $ 0.1 $ 1.2

Report of Business Segments

Report of Business Segments	6 Months Ended
	Jun. 30, 2018
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 six months ended June 30, 2018 and 2017 . Three Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 567.0 $ — $ — $ — $ 567.0 Cost of sales 208.7 — — — 208.7 Other operation and maintenance 123.5 0.3 (0.6 ) — 123.2 Depreciation and amortization 80.9 — — — 80.9 Taxes other than income 21.6 0.2 0.7 — 22.5 Operating income (loss) 132.3 (0.5 ) (0.1 ) — 131.7 Equity in earnings of unconsolidated affiliates — 29.3 — — 29.3 Other income (expense) 10.0 — (0.6 ) (0.9 ) 8.5 Interest expense 39.2 — 2.6 (0.9 ) 40.9 Income tax expense 11.1 6.7 0.1 — 17.9 Net income (loss) $ 92.0 $ 22.1 $ (3.4 ) $ — $ 110.7 Investment in unconsolidated affiliates $ — $ 1,144.6 $ 9.0 $ — $ 1,153.6 Total assets $ 9,447.8 $ 1,147.9 $ 95.6 $ (147.7 ) $ 10,543.6 Three Months Ended June 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 586.4 $ — $ — $ — $ 586.4 Cost of sales 232.1 — — — 232.1 Other operation and maintenance 114.7 0.2 (2.4 ) — 112.5 Depreciation and amortization 73.7 — 1.0 — 74.7 Taxes other than income 20.2 0.3 0.8 — 21.3 Operating income (loss) 145.7 (0.5 ) 0.6 — 145.8 Equity in earnings of unconsolidated affiliates — 29.4 — — 29.4 Other income (expense) 13.8 — (0.5 ) — 13.3 Interest expense 35.6 — 1.5 — 37.1 Income tax expense (benefit) 37.7 10.6 (1.7 ) — 46.6 Net income $ 86.2 $ 18.3 $ 0.3 $ — $ 104.8 Investment in unconsolidated affiliates $ — $ 1,153.9 $ 5.2 $ — $ 1,159.1 Total assets $ 9,199.0 $ 1,513.9 $ 89.2 $ (381.6 ) $ 10,420.5 Six Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,059.7 $ — $ — $ — $ 1,059.7 Cost of sales 419.2 — — — 419.2 Other operation and maintenance 243.2 0.6 (1.8 ) — 242.0 Depreciation and amortization 159.7 — — — 159.7 Taxes other than income 44.3 0.4 1.9 — 46.6 Operating income (loss) 193.3 (1.0 ) (0.1 ) — 192.2 Equity in earnings of unconsolidated affiliates — 63.2 — — 63.2 Other income (expense) 20.6 — (1.3 ) (1.5 ) 17.8 Interest expense 76.5 — 4.5 (1.5 ) 79.5 Income tax expense (benefit) 14.1 16.5 (2.6 ) — 28.0 Net income (loss) $ 123.3 $ 45.7 $ (3.3 ) $ — $ 165.7 Investment in unconsolidated affiliates $ — $ 1,144.6 $ 9.0 $ — $ 1,153.6 Total assets $ 9,447.8 $ 1,147.9 $ 95.6 $ (147.7 ) $ 10,543.6 Six Months Ended June 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,042.4 $ — $ — $ — $ 1,042.4 Cost of sales 440.8 — — — 440.8 Other operation and maintenance 239.4 0.3 (5.1 ) — 234.6 Depreciation and amortization 128.4 — 1.9 — 130.3 Taxes other than income 42.5 0.5 2.2 — 45.2 Operating income (loss) 191.3 (0.8 ) 1.0 — 191.5 Equity in earnings of unconsolidated affiliates — 65.0 — — 65.0 Other income (expense) 25.3 0.1 (2.3 ) (0.1 ) 23.0 Interest expense 69.2 — 3.0 (0.1 ) 72.1 Income tax expense (benefit) 45.0 26.0 (4.4 ) — 66.6 Net income $ 102.4 $ 38.3 $ 0.1 $ — $ 140.8 Investment in unconsolidated affiliates $ — $ 1,153.9 $ 5.2 $ — $ 1,159.1 Total assets $ 9,199.0 $ 1,513.9 $ 89.2 $ (381.6 ) $ 10,420.5

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
Long-term Purchase Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingencies Except as set forth below, in Note 14 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 13 and 14 to the Company's Consolidated Financial Statements included in the Company's 2017 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. Management believes that all of 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. OG&E is managing several potentially material 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. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. 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 expected to be completed in late 2018 to early 2019. More detail regarding the ECP can be found in Note 14 under "Pending Regulatory Matters." 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	6 Months Ended
	Jun. 30, 2018
Regulated Operations [Abstract]
Rate Matters and Regulation	Rate Matters and Regulation Except as set forth below, the circumstances set forth in Note 14 to the Company's Consolidated Financial Statements included in the Company's 2017 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. References to "March 2017 OCC rate order" below and in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" indicate the general rate review order OG&E received from the OCC on March 20, 2017, as detailed further in "Note 14. Rate Matters and Regulation" in the Company's 2017 Form 10-K. Completed Regulatory Matters Oklahoma Rate Review Filing - 2018 On January 16, 2018, OG&E filed a general rate review in Oklahoma, requesting a rate increase of $1.9 million per year, assuming a 9.9 percent return on equity. The filing sought recovery of the seven combustion turbines that are part of the Mustang Modernization Plan, an increase in depreciation rates to levels similar with rates in existence prior to the March 2017 OCC rate order and credit to customers for the impacts of the 2017 Tax Act, which was enacted on December 22, 2017. On December 22, 2017, the Attorney General of Oklahoma requested that the OCC reduce the rates and charges for electric service and provide for an immediate refund due to the customers of OG&E resulting from the 2017 Tax Act. In response, on January 4, 2018, the OCC ordered OG&E to record a reserve, beginning on January 4, 2018, to reflect the reduced federal corporate tax rate of 21 percent and the amortization of excess accumulated deferred income tax and any other tax implications of the 2017 Tax Act on an interim basis, subject to refund until utility rates are adjusted to reflect the federal tax savings and a final order is issued in the rate review. Further, the OCC ordered the amounts of any refunds of such reserves owed to customers should accrue interest at a rate equivalent to OG&E's cost of capital as previously recognized in the March 2017 OCC rate order. OG&E has reserved the excess income taxes collected in current rates and any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus interest, from January 2018 through June 2018. On June 19, 2018, the OCC approved a Joint Stipulation and Settlement Agreement. Key terms of the settlement include the following: • an annual net decrease of $64.0 million in OG&E's rates to its Oklahoma retail customers, which reflects recovery of the Mustang Modernization Plan, offset by reductions for the impact of the lower corporate income taxes resulting from the 2017 Tax Act; • for purposes of calculating the Allowance for Funds Used During Construction and OG&E's various recovery riders that include a full return component, use of the most-recently approved return on equity of 9.5 percent and a capital structure of 47 percent debt/ 53 percent equity; • depreciation rates remain unchanged from the current depreciation rates approved in the March 2017 OCC rate order; • regulatory asset treatment for the Dry Scrubbers at Sooner Units 1 and 2 that will defer the non-fuel operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes, subject to a prudence review in a future general rate review and a determination as to whether the project is used and useful; • production tax credits will be removed from base rates and placed into a separate rider; • a federal tax credit rider will be established to refund to customers the amount of excess taxes received from January to June 2018, as discussed above, and the ongoing annual true up of excess accumulated deferred income taxes resulting from the reduction in corporate income tax rates as part of the 2017 Tax Act (further discussed in Note 7); and • the demand program rider tariff will be revised to allow for concurrent recovery of lost revenues from foregone sales due to certain achieved energy efficiency and demand savings. As a result of the settlement, new rates were implemented on July 1, 2018, reflecting the impacts of the order, and the tax reserve balance estimated for January 2018 through June 2018 was returned to Oklahoma customers during the July billing cycle. Demand Program Rider - Energy Efficiency Lost Net Revenues During the May 2017 implementation of new rates from the March 2017 OCC rate order, OG&E reserved $5.6 million , pending resolution of a dispute with the OCC's Public Utility Division staff regarding recovery of certain lost revenues associated with energy efficiency programs incurred prior to the March 2017 OCC rate order. These lost revenues are included within the total Demand Program Rider regulatory asset balance of $16.7 million as disclosed in Note 1. This dispute was resolved through the June 19, 2018 OCC settlement; as a result, the reserve has been reversed, and an adjustment has been recorded to the Demand Program Rider regulatory asset balance. Fuel Adjustment Clause Review for Calendar Year 2016 On August 3, 2017, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2016, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 7, 2018, an intervenor filed a recommendation to disallow the Oklahoma jurisdictional portion of $3.3 million related to wind sales in the SPP. On April 4, 2018, a Joint Stipulation and Settlement Agreement was filed with the OCC. As part of the agreement, the stipulating parties settled all claims regarding the issue of wind energy settlement costs for the period September 2016 through May 2017, and OG&E agreed to refund $2.4 million to customers related to wind sales in the SPP. On April 25, 2018, the OCC approved the Joint Stipulation and Settlement Agreement, and in May 2018, OG&E refunded this settlement amount to customers. FERC - Request for Waiver On May 22, 2018, OG&E submitted a request for waiver of applicable formula rate provisions in OG&E's Open Access Transmission Tariff and SPP, Inc.'s Open Access Transmission Tariff. OG&E requested a waiver, effective January 1, 2018, to revise its 2018 projected net revenue requirement to reflect the federal corporate income tax rate reduction from 35 percent to 21 percent as a result of the 2017 Tax Act. On June 29, 2018, the FERC granted OG&E's request for waiver, effective January 1, 2018, which will allow OG&E to lower its current year projected net revenue requirement and provide benefits to customers through lower rates more promptly than if OG&E were to wait until the current year true-up adjustment to recognize the reduced federal corporate income tax rate. OG&E is reserving the excess income taxes collected in current rates, plus interest, from January 2018 to the date the new tax rate is reflected in billings based on the order received from the FERC. Once the SPP adjusts the rates billed to OG&E's customers, OG&E will begin reversing the reserve as the previous months in 2018 are resettled based on the lower tax rate. APSC Order - 2017 Tax Act On January 12, 2018, as a result of the 2017 Tax Act, the APSC ordered OG&E to prepare and file an analysis, within 30 days of this order, of the ratemaking effects of the 2017 Tax Act on OG&E's revenue requirement and begin, effective January 1, 2018, to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act. On July 26, 2018, the APSC ordered OG&E to file, within 30 days of this order, a separate rider that includes the reduction in tax expense due to the 2017 Tax Act and amortization of the applicable excess accumulated deferred income taxes as a reduction in revenue requirement effective from January 1, 2018 to the date that OG&E's first year Formula Rate Plan filing goes into effect in April 2019. OG&E is reserving the excess income taxes collected in current rates and any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus carrying charges, from January 2018 to the effective date of the rider. 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 under Oklahoma Statute Title 17, Section 286 (B) 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 and approval for a recovery mechanism for the associated costs. 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 under Oklahoma Statute Title 17, Section 286 (B), and on December 23, 2015, the OCC rejected OG&E's motion. On February 12, 2016, OG&E filed an application under Oklahoma Statute Title 17, Section 151, et seq. requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. 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 a general rate review. On April 28, 2016, the OCC approved the Dry Scrubber project. Two parties appealed the OCC's decision to the Oklahoma Supreme Court. On April 24, 2018, the Oklahoma Supreme Court ruled that the OCC did not have the authority to grant pre-approval of OG&E's Dry Scrubber project outside the authority of Oklahoma Statute Title 17, Section 286 (B). OG&E intends to seek recovery of the Dry Scrubber total cost in a general rate review after the project is completed. OG&E anticipates the total cost of Dry Scrubbers will be $542.4 million , including allowance for funds used during construction and capitalized ad valorem taxes and expects the project to be completed in late 2018 to early 2019. As of June 30, 2018 , OG&E has invested $451.6 million in the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $385.0 million , including allowance for funds used during construction and capitalized ad valorem taxes . As of June 30, 2018 , OG&E has invested $376.3 million in the Mustang Modernization Plan. All seven combustion turbines have been placed into service, and a majority of the project is complete, with only minor items remaining for completion in the second half of 2018. Integrated Resource Plans In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. 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 plan. Currently, OG&E is scheduled to update its IRP in Oklahoma by October 1, 2018 and in Arkansas by October 31, 2018. FERC - Section 206 Filing In January 2018, the Oklahoma Municipal Power Authority filed a complaint at the FERC stating that the base return on common equity used by OG&E in calculating formula transmission rates under the SPP Open Access Transmission Tariff is unjust and unreasonable and should be reduced from 10.60 percent to 7.85 percent , effective upon the date of the complaint. The Company is analyzing the potential impact of the complaint but estimates that if the FERC ultimately orders a reduction, each 25 basis point reduction in the requested return on equity would reduce the Company's SPP Open Access Transmission Tariff transmission revenues by approximately $1.5 million annually. OG&E contested the reduction of its base return on equity. The Company is unable to predict what action the FERC will take in response to the Oklahoma Municipal Power Authority's complaint or the timing of such action. However, if the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could have a material adverse effect on the Company's consolidated financial position, results of operations and cash flows. In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. OG&E is reserving the excess income taxes collected in current rates, plus interest, from January 2018 to the date the new tax rate is reflected in billings based on the order received from the FERC, as discussed under "FERC - Request for Waiver" above. Further, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act. Fuel Adjustment Clause Review for Calendar Year 2017 On July 9, 2018, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2017, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. A preliminary hearing on procedural issues was held on July 19, 2018. OG&E expects to file its Minimum Filing Requirements and Supporting Testimony on September 7, 2018.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2018
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 U.S. 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 it 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 wholly owned subsidiaries and ultimately 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 the Company and CenterPoint, 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 June 30, 2018 and December 31, 2017 , the consolidated results of its operations for the three and six months ended June 30, 2018 and 2017 and its consolidated cash flows for the six months ended June 30, 2018 and 2017 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after June 30, 2018 up to the date of issuance of these Condensed Consolidated Financial Statements, and these statements contain all necessary adjustments and disclosures resulting from that evaluation. Due to seasonal fluctuations and other factors , the Company's operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 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 2017 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 or liabilities, which could have significant financial effects.
Equity Method Investments [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 Affiliates 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; therefore, 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 at June 30, 2018 as presented in Note 12. 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.
Revenue Recognition, Policy [Policy Text Block]	OG&E recognizes revenue from electric sales when power is delivered to customers. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Condensed Consolidated Balance Sheets and in Revenues from Contracts with Customers on the Condensed Consolidated Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Fair Value of Financial Instruments, Policy [Policy Text Block]	The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1), and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). The Company had no financial instruments measured at fair value on a recurring basis at June 30, 2018 and December 31, 2017 . 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 is classified as Level 3 in the fair value hierarchy as its fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate.
Income Tax, Policy [Policy Text Block]	Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate. The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions.
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Share Basic earnings per share is calculated by dividing net income attributable to 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 Accoun24

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2018
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. June 30, December 31, (In millions) 2018 2017 REGULATORY ASSETS Current: Oklahoma demand program rider under recovery (A) $ 16.7 $ 31.6 SPP cost tracker under recovery (A) 0.8 7.7 Other (A) 2.2 1.5 Total current regulatory assets $ 19.7 $ 40.8 Non-current: Benefit obligations regulatory asset $ 171.9 $ 177.2 Deferred storm expenses 39.0 42.2 Smart Grid 29.3 32.8 Unamortized loss on reacquired debt 11.8 12.3 Other 18.2 18.5 Total non-current regulatory assets $ 270.2 $ 283.0 REGULATORY LIABILITIES Current: Fuel clause over recoveries $ 38.7 $ 1.7 Other (B) 2.5 2.2 Total current regulatory liabilities $ 41.2 $ 3.9 Non-current: Income taxes refundable to customers, net $ 944.2 $ 955.5 Accrued removal obligations, net 300.2 288.4 Pension tracker 44.4 32.3 Other 7.3 7.2 Total non-current regulatory liabilities $ 1,296.1 $ 1,283.4 (A) Included in Other Current Assets on the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following tables summarize changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months ended June 30, 2018 and 2017 . All amounts below are presented net of tax. Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service credit Total Balance at December 31, 2017 $ (32.7 ) $ — $ 2.5 $ 7.0 $ (23.2 ) Amounts reclassified from accumulated other comprehensive income (loss) 1.7 — — (0.8 ) 0.9 Balance at June 30, 2018 $ (31.0 ) $ — $ 2.5 $ 6.2 $ (22.3 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service credit Total Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) Amounts reclassified from accumulated other comprehensive income 1.4 — — — 1.4 Balance at June 30, 2017 $ (30.7 ) $ 0.1 $ 2.7 $ — $ (27.9 )
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 six months ended June 30, 2018 and 2017 . Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Condensed Consolidated Statements of Income Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Amortization of Pension Plan and Restoration of Retirement Income Plan items: Actuarial losses (A) $ (1.3 ) $ (1.2 ) $ (2.2 ) $ (2.2 ) Other Net Periodic Benefit Income (Expense) (0.3 ) (0.4 ) (0.5 ) (0.8 ) Income Tax Expense $ (1.0 ) $ (0.8 ) $ (1.7 ) $ (1.4 ) Net Income Amortization of postretirement benefit plans items: Prior service credit (A) $ 0.5 $ — $ 1.1 $ — Other Net Periodic Benefit Income (Expense) 0.2 — 0.3 — Income Tax Expense $ 0.3 $ — $ 0.8 $ — Net Income Total reclassifications for the period, net of tax $ (0.7 ) $ (0.8 ) $ (0.9 ) $ (1.4 ) Net Income (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Revenue from Contracts with C25

Revenue from Contracts with Customers (Tables)	6 Months Ended
	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Disaggregation of Revenue [Table Text Block]	The following table disaggregates the Company's revenues from contracts with customers by customer classification. The Company's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations." June 30, 2018 (In millions) Three Months Ended Six Months Ended Residential $ 217.3 $ 413.5 Commercial 152.4 270.2 Industrial 47.7 89.4 Oilfield 37.7 71.5 Public authorities and street light 51.1 92.8 System sales revenues 506.2 937.4 Provision for rate refund (16.5 ) (19.7 ) Integrated market 13.1 21.8 Transmission 40.2 76.0 Other 4.7 10.1 Revenues from contracts with customers $ 547.7 $ 1,025.6

Investment in Unconsolidated 26

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 2018
Reconciliation of Basis Difference [Line Items]
Reconciliation of Basis Difference [Table Text Block]	The following table reconciles the basis difference in Enable from December 31, 2017 to June 30, 2018 . (In millions) Basis difference at December 31, 2017 $ 714.2 Change in Enable basis difference (3.1 ) Amortization of basis difference (5.6 ) Elimination of Enable fair value step up (8.6 ) Basis difference at June 30, 2018 $ 696.9
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]	The following table reconciles the Company's equity in earnings of unconsolidated affiliates for the three and six months ended June 30, 2018 and 2017 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Enable net income $ 86.4 $ 86.2 $ 191.0 $ 197.4 OGE Energy's percent ownership at period end 25.6 % 25.7 % 25.6 % 25.7 % OGE Energy's portion of Enable net income 22.2 22.2 49.0 50.7 Amortization of basis difference 2.8 2.9 5.6 5.7 Elimination of Enable fair value step up 4.3 4.3 8.6 8.6 Equity in earnings of unconsolidated affiliates $ 29.3 $ 29.4 $ 63.2 $ 65.0
Schedule of Related Party Transactions [Table Text Block]	The following table summarizes related party transactions between OG&E and Enable during the three and six months ended June 30, 2018 and 2017 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Operating revenues: Electricity to power electric compression assets $ 3.6 $ 3.3 $ 7.6 $ 5.5 Cost of sales: Natural gas transportation services $ 8.8 $ 8.8 $ 17.5 $ 17.5 Natural gas purchases (sales) $ 2.2 $ (0.4 ) $ 2.5 $ (0.8 )
Summarized Balance Sheet Financial Information, Equity Method Investment [Table Text Block]	Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2018 and December 31, 2017 and for the three and six months ended June 30, 2018 and 2017 . June 30, December 31, Balance Sheet 2018 2017 (In millions) Current assets $ 432 $ 416 Non-current assets $ 11,360 $ 11,177 Current liabilities $ 1,258 $ 1,279 Non-current liabilities $ 2,963 $ 2,660
Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]	Three Months Ended Six Months Ended June 30, June 30, Income Statement 2018 2017 2018 2017 (In millions) Operating revenues $ 805 $ 626 $ 1,553 $ 1,292 Cost of natural gas and NGLs $ 444 $ 279 $ 819 $ 587 Operating income $ 126 $ 122 $ 265 $ 262 Net income $ 86 $ 86 $ 191 $ 197

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2018
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 June 30, 2018 and December 31, 2017 . June 30, December 31, 2018 2017 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year): Senior Notes $ 2,855.2 $ 3,101.4 $ 2,854.3 $ 3,242.8 OG&E Industrial Authority Bonds $ 135.4 $ 135.4 $ 135.4 $ 135.4 Tinker Debt $ 9.7 $ 9.1 $ 9.7 $ 9.8

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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 six months ended June 30, 2018 and 2017 related to the Company's performance units and restricted stock . Three Months Ended June 30, Six Months Ended June 30, (In millions) 2018 2017 2018 2017 Performance units: Total shareholder return $ 2.1 $ 1.8 $ 4.1 $ 3.3 Earnings per share 1.0 0.6 1.7 1.2 Total performance units 3.1 2.4 5.8 4.5 Restricted stock — — — — Total compensation expense $ 3.1 $ 2.4 $ 5.8 $ 4.5 Income tax benefit $ 0.8 $ 1.0 $ 1.5 $ 1.8

Common Equity (Tables)

Common Equity (Tables)	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The following table calculates basic and diluted earnings per share for the Company. Three Months Ended June 30, Six Months Ended June 30, (In millions except per share data) 2018 2017 2018 2017 Net income $ 110.7 $ 104.8 $ 165.7 $ 140.8 Average common shares outstanding: Basic average common shares outstanding 199.7 199.7 199.7 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.8 0.2 0.6 0.3 Diluted average common shares outstanding 200.5 199.9 200.3 200.0 Basic earnings per average common share $ 0.55 $ 0.52 $ 0.83 $ 0.70 Diluted earnings per average common share $ 0.55 $ 0.52 $ 0.83 $ 0.70 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2018
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 included in the following table. SERIES DATE DUE AMOUNT (In millions) 1.06% - 2.00% Garfield Industrial Authority, January 1, 2025 $ 47.0 1.05% - 1.83% Muskogee Industrial Authority, January 1, 2025 32.4 1.06% - 1.86% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4

Short-Term Debt and Credit Fa31

Short-Term Debt and Credit Facilities (Tables)	6 Months Ended
	Jun. 30, 2018
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	The following table provides information regarding the Company's revolving credit agreements at June 30, 2018 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ 200.1 2.31 % (D) March 8, 2023 (E) OG&E (C) 450.0 0.3 0.95 % (D) March 8, 2023 (E) Total $ 900.0 $ 200.4 2.31 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2018 . (B) This bank facility is available to back up the Company'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) In March 2017, the Company and OG&E entered into unsecured five-year revolving credit agreements totaling $900.0 million ( $450.0 million for the Company and $450.0 million for OG&E). Each of the facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. Effective March 9, 2018, the Company and OG&E utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023.

Retirement Plans and Postreti32

Retirement Plans and Postretirement Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2018
Defined Benefit Plan [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following tables present the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Condensed Consolidated Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss and amortization of unrecognized prior service cost are presented within Other Net Periodic Benefit Income (Expense) on the Company's Condensed Consolidated Statements of Income. Pension Plan Restoration of Retirement Three Months Ended Six Months Ended Three Months Ended Six Months Ended June 30, June 30, June 30, June 30, (In millions) 2018 2017 2018 2017 2018 2017 2018 2017 Service cost $ 3.4 $ 3.5 $ 7.5 $ 7.7 $ 0.1 $ 0.1 $ 0.2 $ 0.2 Interest cost 5.8 6.6 11.7 13.1 0.1 — 0.2 0.1 Expected return on plan assets (11.0 ) (10.6 ) (22.3 ) (21.3 ) — — — — Amortization of net loss 4.4 4.7 8.3 8.7 0.3 0.1 0.4 0.2 Total net periodic benefit cost 2.6 4.2 5.2 8.2 0.5 0.2 0.8 0.5 Less: Amount paid by unconsolidated affiliates 0.7 0.9 1.2 1.7 — — — — Net periodic benefit cost $ 1.9 $ 3.3 $ 4.0 $ 6.5 $ 0.5 $ 0.2 $ 0.8 $ 0.5 (A) In addition to the $2.4 million and $3.5 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017 , respectively , the Company recognized the following: • an increase in pension expense during the three months ended June 30, 2018 and 2017 of $3.8 million and $2.9 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1) ; and • a deferral of pension expense during the three months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013. (B) In addition to the $4.8 million and $7.0 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017 , respectively, the Company recognized the following: • an increase in pension expense during the six months ended June 30, 2018 and 2017 of $7.8 million and $5.8 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the six months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013. Postretirement Benefit Plans Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 (B) 2017 (B) 2018 (C) 2017 (C) Service cost $ 0.1 $ 0.2 $ 0.2 $ 0.4 Interest cost 1.3 2.1 2.6 4.3 Expected return on plan assets (0.5 ) (0.5 ) (1.0 ) (1.1 ) Amortization of net loss 0.9 0.2 1.9 0.8 Amortization of unrecognized prior service cost (A) (2.1 ) — (4.2 ) — Total net periodic benefit cost (0.3 ) 2.0 (0.5 ) 4.4 Less: Amount paid by unconsolidated affiliates (0.1 ) 0.2 (0.2 ) 0.6 Net periodic benefit cost $ (0.2 ) $ 1.8 $ (0.3 ) $ 3.8 (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 $0.2 million of net periodic benefit income and $1.8 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017 , respectively, the Company recognized an increase in postretirement medical expense in the three months ended June 30, 2018 and 2017 of $2.2 million and $1.0 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 $0.3 million of net periodic benefit income and $3.8 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017 , respectively, the Company recognized an increase in postretirement medical expense in the six months ended June 30, 2018 and 2017 of $4.3 million and $2.1 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]	As required by ASU 2017-07, the Company only capitalizes the service cost component of net benefit cost, beginning in the first quarter of 2018. Prior year capitalized amounts were not adjusted, as this change was implemented on a prospective basis. Three Months Ended Six Months Ended June 30, June 30, (In millions) 2018 2017 2018 2017 Capitalized portion of net periodic pension benefit cost $ 0.9 $ 1.2 $ 1.9 $ 2.3 Capitalized portion of net periodic postretirement benefit cost $ 0.1 $ 0.5 $ 0.1 $ 1.2

Report of Business Segments (Ta

Report of Business Segments (Tables)	6 Months Ended
	Jun. 30, 2018
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 six months ended June 30, 2018 and 2017 . Three Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 567.0 $ — $ — $ — $ 567.0 Cost of sales 208.7 — — — 208.7 Other operation and maintenance 123.5 0.3 (0.6 ) — 123.2 Depreciation and amortization 80.9 — — — 80.9 Taxes other than income 21.6 0.2 0.7 — 22.5 Operating income (loss) 132.3 (0.5 ) (0.1 ) — 131.7 Equity in earnings of unconsolidated affiliates — 29.3 — — 29.3 Other income (expense) 10.0 — (0.6 ) (0.9 ) 8.5 Interest expense 39.2 — 2.6 (0.9 ) 40.9 Income tax expense 11.1 6.7 0.1 — 17.9 Net income (loss) $ 92.0 $ 22.1 $ (3.4 ) $ — $ 110.7 Investment in unconsolidated affiliates $ — $ 1,144.6 $ 9.0 $ — $ 1,153.6 Total assets $ 9,447.8 $ 1,147.9 $ 95.6 $ (147.7 ) $ 10,543.6 Three Months Ended June 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 586.4 $ — $ — $ — $ 586.4 Cost of sales 232.1 — — — 232.1 Other operation and maintenance 114.7 0.2 (2.4 ) — 112.5 Depreciation and amortization 73.7 — 1.0 — 74.7 Taxes other than income 20.2 0.3 0.8 — 21.3 Operating income (loss) 145.7 (0.5 ) 0.6 — 145.8 Equity in earnings of unconsolidated affiliates — 29.4 — — 29.4 Other income (expense) 13.8 — (0.5 ) — 13.3 Interest expense 35.6 — 1.5 — 37.1 Income tax expense (benefit) 37.7 10.6 (1.7 ) — 46.6 Net income $ 86.2 $ 18.3 $ 0.3 $ — $ 104.8 Investment in unconsolidated affiliates $ — $ 1,153.9 $ 5.2 $ — $ 1,159.1 Total assets $ 9,199.0 $ 1,513.9 $ 89.2 $ (381.6 ) $ 10,420.5 Six Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,059.7 $ — $ — $ — $ 1,059.7 Cost of sales 419.2 — — — 419.2 Other operation and maintenance 243.2 0.6 (1.8 ) — 242.0 Depreciation and amortization 159.7 — — — 159.7 Taxes other than income 44.3 0.4 1.9 — 46.6 Operating income (loss) 193.3 (1.0 ) (0.1 ) — 192.2 Equity in earnings of unconsolidated affiliates — 63.2 — — 63.2 Other income (expense) 20.6 — (1.3 ) (1.5 ) 17.8 Interest expense 76.5 — 4.5 (1.5 ) 79.5 Income tax expense (benefit) 14.1 16.5 (2.6 ) — 28.0 Net income (loss) $ 123.3 $ 45.7 $ (3.3 ) $ — $ 165.7 Investment in unconsolidated affiliates $ — $ 1,144.6 $ 9.0 $ — $ 1,153.6 Total assets $ 9,447.8 $ 1,147.9 $ 95.6 $ (147.7 ) $ 10,543.6 Six Months Ended June 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,042.4 $ — $ — $ — $ 1,042.4 Cost of sales 440.8 — — — 440.8 Other operation and maintenance 239.4 0.3 (5.1 ) — 234.6 Depreciation and amortization 128.4 — 1.9 — 130.3 Taxes other than income 42.5 0.5 2.2 — 45.2 Operating income (loss) 191.3 (0.8 ) 1.0 — 191.5 Equity in earnings of unconsolidated affiliates — 65.0 — — 65.0 Other income (expense) 25.3 0.1 (2.3 ) (0.1 ) 23.0 Interest expense 69.2 — 3.0 (0.1 ) 72.1 Income tax expense (benefit) 45.0 26.0 (4.4 ) — 66.6 Net income $ 102.4 $ 38.3 $ 0.1 $ — $ 140.8 Investment in unconsolidated affiliates $ — $ 1,153.9 $ 5.2 $ — $ 1,159.1 Total assets $ 9,199.0 $ 1,513.9 $ 89.2 $ (381.6 ) $ 10,420.5

Summary of Significant Accoun34

Summary of Significant Accounting Policies Equity Ownership (Details)	Jun. 30, 2018
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		Jun. 30, 2018	Dec. 31, 2017
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause over recoveries		$ 38.7	$ 1.7
Current Regulatory Assets		19.7	40.8
Non-Current Regulatory Assets		270.2	283
Current Regulatory Liabilities		41.2	3.9
Non-Current Regulatory Liabilities		1,296.1	1,283.4
Other (B)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	2.5	2.2
Non-Current Regulatory Liabilities		7.3	7.2
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		944.2	955.5
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		300.2	288.4
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		44.4	32.3
Oklahoma demand program rider under recovery (A)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	16.7	31.6
SPP cost tracker under recovery (A)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	0.8	7.7
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		171.9	177.2
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		39	42.2
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		29.3	32.8
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		11.8	12.3
Other Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	2.2	1.5
Non-Current Regulatory Assets		$ 18.2	$ 18.5
[1]	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
[2]	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.

Summary of Significant Accoun36

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (22.3)	$ (27.9)	$ (23.2)	$ (29.3)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.9	1.4
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(31)	(30.7)	(32.7)	(32.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1.7	1.4
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Other Postretirement Benefits Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	2.5	2.7	2.5	2.7
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	0	0.1	0	0.1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefits Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	6.2	0	$ 7	$ 0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ (0.8)	$ 0

Summary of Significant Accoun37

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) Reclassifications out of AOCI (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		$ (0.7)	$ (0.8)	$ (0.9)	$ (1.4)
Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	[1]	(1.3)	(1.2)	(2.2)	(2.2)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(0.3)	(0.4)	(0.5)	(0.8)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(1)	(0.8)	(1.7)	(1.4)
Other Postretirement Benefits Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	[1]	0.5	0	1.1	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		0.2	0	0.3	0
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ 0.3	$ 0	$ 0.8	$ 0
[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Revenue from Contracts with C38

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 547.7	$ 0	$ 1,025.6	$ 0
Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	217.3		413.5
Commercial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	152.4		270.2
Industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	47.7		89.4
Oilfield
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	37.7		71.5
Public authorities and street light
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	51.1		92.8
System sales revenues
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	506.2		937.4
Provision for rate refund
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(16.5)		(19.7)
Integrated market
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	13.1		21.8
Transmission
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	40.2		76
Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 4.7		$ 10.1

Investment in Unconsolidated 39

Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	May 01, 2013
Expected Settlement Charge			$ 13.8
Limited Partner Units Owned	111		111
Distribution Made to Limited Partner, Distributions Declared, Per Unit			$ 0.31800
Equity in earnings of unconsolidated affiliates	$ 29.3	$ 29.4	$ 63.2	$ 65
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	696.9		696.9		$ 714.2
Enogex LLC [Member]
Percentage of Enogex LLC Contributed						100.00%
Increase in fair value of net assets						$ 2,200
Enable Midstream Partners [Member]
Distributions from unconsolidated affiliates	$ 35.3	$ 35.3	$ 70.6	$ 70.6
OGE Holdings [Member]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.60%	25.70%	25.60%	25.70%

Investment in Unconsolidated 40

Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 0		$ 0		$ 1.9
Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Proceeds from Equity Method Investment, Distribution	35.3	$ 35.3	70.6	$ 70.6
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	3.6	3.3	7.6	5.5
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	0.2	0.7	0.3	1.5
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	5.2	7.3	16.8	17.3
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	17.5	17.5
Natural Gas Purchases [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	2.2	$ (0.4)	2.5	$ (0.8)
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 1.8		$ 1.8		$ 2

Investment in Unconsolidated 41

Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 432	$ 416
Non-current assets	11,360	11,177
Current liabilities	1,258	1,279
Non-current liabilities	$ 2,963	$ 2,660

Investment in Unconsolidated 42

Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	$ 29.3	$ 29.4	$ 63.2	$ 65
Operating revenues	805	626	1,553	1,292
Cost of natural gas and NGLs	444	279	819	587
Operating income	126	122	265	262
Net income	$ 86.4	$ 86.2	$ 191	$ 197.4

Investment in Unconsolidated 43

Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Net income	$ 86.4	$ 86.2	$ 191	$ 197.4
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	696.9		696.9		$ 714.2
Proportionate Unconsolidated Affiliate Net Income	22.2	22.2	49	50.7
Amortization of basis difference	2.8	2.9	5.6	5.7
Elimination of Enable fair value step up	4.3	4.3	8.6	8.6
Equity in earnings of unconsolidated affiliates	$ 29.3	$ 29.4	63.2	$ 65
Equity in Earnings Change in Basis Difference			$ (3.1)
OGE Holdings [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.60%	25.70%	25.60%	25.70%

Fair Value Measurements, Fair V

Fair Value Measurements, Fair Value Hierarchy (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

Fair Value Measurements Carryin

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 2,855.2	$ 2,854.3
Long-Term Debt, Fair Value	3,101.4	3,242.8
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	9.7	9.7
Long-Term Debt, Fair Value	9.1	9.8
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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Stock-Based Compensation Activity
Income tax benefit	$ 0.8	$ 1	$ 1.5	$ 1.8
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	3.1	2.4	5.8	4.5
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	0	0	0	0
Stock Compensation Plan [Member]
Stock-Based Compensation Activity
Compensation expense	3.1	2.4	5.8	4.5
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	2.1	1.8	4.1	3.3
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 1	$ 0.6	$ 1.7	$ 1.2

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Non-Current Regulatory Liabilities	$ 1,296.1	$ 1,283.4
Interim Rate Revenue Reserved	32.8
Income taxes recoverable from customers, net [Member]
Non-Current Regulatory Liabilities	$ 1,028

Common Equity Automatic Dividen

Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - shares	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Equity [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 110.7	$ 104.8	$ 165.7	$ 140.8
Basic average common shares outstanding	199.7	199.7	199.7	199.7
Contingently issuable shares (performance and restricted stock units)	0.8	0.2	0.6	0.3
Diluted average common shares outstanding	200.5	199.9	200.3	200
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share	$ 0.55	$ 0.52	$ 0.83	$ 0.70
Diluted earnings per average common share	$ 0.55	$ 0.52	$ 0.83	$ 0.70
Anti-dilutive shares excluded from earnings per share calculation	0	0	0	0

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)
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	1.06%
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	1.05%
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	1.06%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.00%
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	1.83%
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	1.86%

Short-Term Debt and Credit Fa51

Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Short-term debt		$ 200.1	$ 168.4
Line of Credit Facility [Abstract]
Aggregate Commitment		900
Long-term Line of Credit	[1]	$ 200.4
Weighted Average Interest Rate		2.31%
OGE Energy [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[2]	$ 450
Line of Credit Facility [Abstract]
Long-term Line of Credit	[1],[2]	$ 200.1
Weighted Average Interest Rate	[2],[3]	2.31%
Maturity	[2],[4]	Mar. 8, 2023
OG&E [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[5]	$ 450
Line of Credit Facility [Abstract]
Letters of Credit Outstanding, Amount	[1],[5]	$ 0.3
Weighted Average Interest Rate	[3],[5]	0.95%
Maturity	[4],[5]	Mar. 8, 2023
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years
[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2018.
[2]	This bank facility is available to back up the Company'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]	In March 2017, the Company and OG&E entered into unsecured five-year revolving credit agreements totaling $900.0 million ($450.0 million for the Company and $450.0 million for OG&E). Each of the facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. Effective March 9, 2018, the Company and OG&E utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023.
[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 Postreti52

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		3 Months Ended				6 Months Ended				12 Months Ended
		Jun. 30, 2018		Jun. 30, 2017		Jun. 30, 2018		Jun. 30, 2017		Dec. 31, 2013
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		$ 2.4		$ 3.5		$ 4.8		$ 7
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		3.4	[1]	3.5	[1]	7.5	[2]	7.7	[2]
Interest cost		5.8	[1]	6.6	[1]	11.7	[2]	13.1	[2]
Expected return on plan assets		11	[1]	10.6	[1]	22.3	[2]	21.3	[2]
Defined Benefit Plan, Amortization of Gain (Loss)		4.4	[1]	4.7	[1]	8.3	[2]	8.7	[2]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		2.6	[1]	4.2	[1]	5.2	[2]	8.2	[2]
Less: Amount paid by unconsolidated affiliates		0.7	[1]	0.9	[1]	1.2	[2]	1.7	[2]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement										$ (22.4)
Capitalized Portion of Net Periodic Benefit Cost		0.9		1.2		1.9		2.3
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		1.9	[1]	3.3	[1]	4	[2]	6.5	[2]
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.1	[1]	0.1	[1]	0.2	[2]	0.2	[2]
Interest cost		0.1	[1]	0	[1]	0.2	[2]	0.1	[2]
Expected return on plan assets		0	[1]	0	[1]	0	[2]	0	[2]
Defined Benefit Plan, Amortization of Gain (Loss)		0.3	[1]	0.1	[1]	0.4	[2]	0.2	[2]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		0.5	[1]	0.2	[1]	0.8	[2]	0.5	[2]
Less: Amount paid by unconsolidated affiliates		0	[1]	0	[1]	0	[2]	0	[2]
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		0.5	[1]	0.2	[1]	0.8	[2]	0.5	[2]
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.1	[3]	0.2	[3]	0.2	[4]	0.4	[4]
Interest cost		1.3	[3]	2.1	[3]	2.6	[4]	4.3	[4]
Expected return on plan assets		0.5	[3]	0.5	[3]	1	[4]	1.1	[4]
Defined Benefit Plan, Amortization of Gain (Loss)		0.9	[3]	0.2	[3]	1.9	[4]	0.8	[4]
Amortization of unrecognized prior service cost	[5]	(2.1)	[3]	0	[3]	(4.2)	[4]	0	[4]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		(0.3)	[3]	2	[3]	(0.5)	[4]	4.4	[4]
Less: Amount paid by unconsolidated affiliates		(0.1)	[3]	0.2	[3]	(0.2)	[4]	0.6	[4]
Capitalized Portion of Net Periodic Benefit Cost		0.1		0.5		0.1		1.2
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		(0.2)	[3]	1.8	[3]	(0.3)	[4]	3.8	[4]
OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements		3.8		2.9		7.8		5.8
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements		$ 2.2		1		$ 4.3		2.1
ARKANSAS | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement				$ (2.3)				$ (2.3)
[1]	In addition to the $2.4 million and $3.5 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017, respectively, the Company recognized the following:•an increase in pension expense during the three months ended June 30, 2018 and 2017 of $3.8 million and $2.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and•a deferral of pension expense during the three months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013.
[2]	In addition to the $4.8 million and $7.0 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017, respectively, the Company recognized the following:•an increase in pension expense during the six months ended June 30, 2018 and 2017 of $7.8 million and $5.8 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and•a deferral of pension expense during the six months ended June 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013.
[3]	In addition to the $0.2 million of net periodic benefit income and $1.8 million of net periodic benefit cost recognized during the three months ended June 30, 2018 and 2017, respectively, the Company recognized an increase in postretirement medical expense in the three months ended June 30, 2018 and 2017 of $2.2 million and $1.0 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).
[4]	In addition to the $0.3 million of net periodic benefit income and $3.8 million of net periodic benefit cost recognized during the six months ended June 30, 2018 and 2017, respectively, the Company recognized an increase in postretirement medical expense in the six months ended June 30, 2018 and 2017 of $4.3 million and $2.1 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).
[5]	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.

Report of Business Segments (De

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Operating revenues	$ 567	$ 586.4	$ 1,059.7	$ 1,042.4
Cost of sales	208.7	232.1	419.2	440.8
Other operation and maintenance	123.2	112.5	242	234.6
Depreciation and amortization	80.9	74.7	159.7	130.3
Taxes other than income	22.5	21.3	46.6	45.2
OPERATING INCOME	131.7	145.8	192.2	191.5
Equity in earnings of unconsolidated affiliates	29.3	29.4	63.2	65
Other income (expense)	8.5	13.3	17.8	23
Interest expense	40.9	37.1	79.5	72.1
Income tax expense	17.9	46.6	28	66.6
Net income (loss)	110.7	104.8	165.7	140.8
Investment in unconsolidated affiliates	1,153.6	1,159.1	1,153.6	1,159.1	$ 1,160.4
Total assets	10,543.6	10,420.5	10,543.6	10,420.5	$ 10,412.7
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	567	586.4	1,059.7	1,042.4
Cost of sales	208.7	232.1	419.2	440.8
Other operation and maintenance	123.5	114.7	243.2	239.4
Depreciation and amortization	80.9	73.7	159.7	128.4
Taxes other than income	21.6	20.2	44.3	42.5
OPERATING INCOME	132.3	145.7	193.3	191.3
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income (expense)	10	13.8	20.6	25.3
Interest expense	39.2	35.6	76.5	69.2
Income tax expense	11.1	37.7	14.1	45
Net income (loss)	92	86.2	123.3	102.4
Investment in unconsolidated affiliates	0	0	0	0
Total assets	9,447.8	9,199	9,447.8	9,199
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	0.3	0.2	0.6	0.3
Depreciation and amortization	0	0	0	0
Taxes other than income	0.2	0.3	0.4	0.5
OPERATING INCOME	(0.5)	(0.5)	(1)	(0.8)
Equity in earnings of unconsolidated affiliates	29.3	29.4	63.2	65
Other income (expense)	0	0	0	0.1
Interest expense	0	0	0	0
Income tax expense	6.7	10.6	16.5	26
Net income (loss)	22.1	18.3	45.7	38.3
Investment in unconsolidated affiliates	1,144.6	1,153.9	1,144.6	1,153.9
Total assets	1,147.9	1,513.9	1,147.9	1,513.9
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	(0.6)	(2.4)	(1.8)	(5.1)
Depreciation and amortization	0	1	0	1.9
Taxes other than income	0.7	0.8	1.9	2.2
OPERATING INCOME	(0.1)	0.6	(0.1)	1
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income (expense)	(0.6)	(0.5)	(1.3)	(2.3)
Interest expense	2.6	1.5	4.5	3
Income tax expense	0.1	(1.7)	(2.6)	(4.4)
Net income (loss)	(3.4)	0.3	(3.3)	0.1
Investment in unconsolidated affiliates	9	5.2	9	5.2
Total assets	95.6	89.2	95.6	89.2
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 (expense)	(0.9)	0	(1.5)	(0.1)
Interest expense	(0.9)	0	(1.5)	(0.1)
Income tax expense	0	0	0	0
Net income (loss)	0	0	0	0
Investment in unconsolidated affiliates	0	0	0	0
Total assets	$ (147.7)	$ (381.6)	$ (147.7)	$ (381.6)

Rate Matters and Regulation Rat

Rate Matters and Regulation Rate Matters and Regulation (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2018	Dec. 31, 2017
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 64
Public Utilities, Approved Return on Equity, Percentage		9.50%
Public Utilities, Approved Equity Capital Structure, Percentage		53.00%
Public Utilities, Approved Debt Capital Structure, Percentage		47.00%
Interim Rate Revenue Reserved		$ 32.8
Current Regulatory Assets		19.7	$ 40.8
Recommended Disallowance for Fuel Adjustment		3.3
Refund for Fuel Adjustment		2.4
Dry Scrubber Project [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		451.6
Estimated Environmental Capital Costs		542.4
Mustang Modernization [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		376.3
Estimated Environmental Capital Costs		385
OKLAHOMA
Interim Rate Revenue Reserved		5.6
Oklahoma demand program rider under recovery (A)
Current Regulatory Assets	[1]	16.7	$ 31.6
January 16, 2018 [Member] | OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 1.9
Public Utilities, Requested Return on Equity, Percentage		9.90%
FERC [Member]
Public Utilities, Approved Return on Equity, Percentage		10.60%
Recommended Common Equity Percentage		7.85%
Revenue impact of recommended change in return on common equity		$ 1.5
[1]	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.

Uncategorized Items - oge-20180

Label	Element	Value
Retained Earnings [Member]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	$ 104,800,000
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	$ 110,700,000