OGE Energy (OGE) 10-Q 8 Aug 19 2019 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document	6 Months Ended
	Jun. 30, 2019shares
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-12579
Entity Registrant Name	OGE ENERGY CORP.
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-1481638
Entity Central Index Key	0001021635
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Amendment Flag	false
Title of 12(b) Security	Common Stock
Trading Symbol	OGE
Security Exchange Name	NYSE
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Address, Address Line One	321 North Harvey
Entity Address, Address Line Two	P.O. Box 321
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73101-0321
City Area Code	405
Local Phone Number	553-3000
Entity Common Stock, Shares Outstanding	200,175,812

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues from contracts with customers	$ 501.1	$ 547.7	$ 978.5	$ 1,025.6
Other revenues	12.6	19.3	25.2	34.1
Operating revenues	513.7	567	1,003.7	1,059.7
COST OF SALES	178.7	208.7	391.3	419.2
OPERATING EXPENSES
Other operation and maintenance	119.8	117.2	238.8	229.9
Depreciation and amortization	84.3	80.9	166.7	159.7
Taxes other than income	20.9	22.5	47.2	46.6
Operating expenses	225	220.6	452.7	436.2
OPERATING INCOME	110	137.7	159.7	204.3
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	35.8	29.3	66.5	63.2
Allowance for equity funds used during construction	1.2	6.3	2.7	13.3
Other net periodic benefit expense	(0.3)	(5.2)	(7.3)	(10)
Other income	5	4.7	11.7	10.1
Other expense	(4.4)	(3.3)	(10.1)	(7.7)
Net other income	37.3	31.8	63.5	68.9
INTEREST EXPENSE
Interest on long-term debt	31.8	39.7	64.4	79.3
Allowance for borrowed funds used during construction	(0.6)	(2.8)	(1.6)	(6.5)
Interest on short-term debt and other interest charges	4.7	4	7.7	6.7
Interest expense	35.9	40.9	70.5	79.5
INCOME BEFORE TAXES	111.4	128.6	152.7	193.7
INCOME TAX EXPENSE	11.2	17.9	5.4	28
NET INCOME	$ 100.2	$ 110.7	$ 147.3	$ 165.7
BASIC AVERAGE COMMON SHARES OUTSTANDING	200.2	199.7	200.1	199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.6	200.5	200.5	200.3
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.50	$ 0.55	$ 0.74	$ 0.83
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$ 0.50	$ 0.55	$ 0.73	$ 0.83

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net income	$ 100.2	$ 110.7	$ 147.3	$ 165.7
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.3, $0.3, $0.5 and $0.5, respectively	1	1	1.7	1.7
Settlement cost, net of tax of $0.1, $0.0, $2.3 and $0.0, respectively	0.5	0	7.1	0
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.1), ($0.2), ($0.2) and ($0.3), respectively	(0.4)	(0.3)	(0.9)	(0.8)
Amortization of deferred net gain, net of tax of $0.0, $0.0, $0.0 and $0.0, respectively	0.1	0	0.1	0
Other comprehensive income, net of tax	1	0.7	7.8	0.9
Comprehensive income	$ 101.2	$ 111.4	$ 155.1	$ 166.6

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.3	$ 0.3	$ 0.5	$ 0.5
Postretirement Benefit Plans:
Amortization of prior service cost	(0.1)	(0.2)	(0.2)	(0.3)
Other Comprehensive Income Reclassification Of Defined Benefit Postretirement Plans Net Gain Loss Recognized In Net Periodic Benefit Cost Tax	0	0	0	0
Pension Plan [Member]
Other Comprehensive Income (Loss), Defined Benefit Plan, Adjustment for Settlement or Curtailment Gain (Loss), Tax	$ 0.1	$ 0	$ 2.3	$ 0

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 147.3	$ 165.7
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	166.7	159.7
Deferred income taxes and investment tax credits, net	(1.9)	19.4
Equity in earnings of unconsolidated affiliates	(66.5)	(63.2)
Distributions from unconsolidated affiliates	70.6	63.2
Allowance for equity funds used during construction	(2.7)	(13.3)
Stock-based compensation expense	5.9	5.8
Regulatory assets	(25.6)	(1.6)
Regulatory liabilities	(21.1)	1.9
Other assets	3.2	(7.3)
Other liabilities	13.9	(0.6)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	(12.5)	(51.5)
Increase (Decrease) in Income Taxes Receivable	(3.6)	2
Fuel, materials and supplies inventories	7.2	0.1
Fuel recoveries	(28.9)	37
Other current assets	(4.5)	22
Accounts payable	(83.4)	(45.7)
Other current liabilities	(36.1)	50
Net cash provided from operating activities	128.8	354.2
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(314.5)	(273.8)
Investment in unconsolidated affiliates	(3.2)	(0.5)
Return of capital - unconsolidated affiliates	0	7.4
Net cash used in investing activities	(317.7)	(266.9)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Issuance of Long-term Debt	295.9	0
Increase in short-term debt	207.5	31.7
Payment of long-term debt	(250)	0
Dividends paid on common stock	(148.6)	(133)
Expense of common stock	(10.2)	(0.4)
Net cash provided from (used in) financing activities	94.6	(101.7)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(94.3)	(14.4)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	94.3	14.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 0	$ 94.3
Accounts receivable, less reserve of $1.3 and $1.7, respectively	163.6	174.7
Accrued unbilled revenues	86.2	62.6
Income taxes receivable	6.3	9.9
Fuel inventories	47.9	57.6
Materials and supplies, at average cost	86.9	126.7
Fuel clause under recoveries	30.7	2
Other	34	29.5
Total current assets	455.6	557.3
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,171.3	1,177.5
Other	81.4	73.4
Total other property and investments	1,252.7	1,250.9
PROPERTY, PLANT AND EQUIPMENT
In service	12,516.7	11,994.8
Construction work in progress	126.8	376.4
Total property, plant and equipment	12,643.5	12,371.2
Less: accumulated depreciation	3,766	3,727.4
Net property, plant and equipment	8,877.5	8,643.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	290	285.8
Other	10.4	10.8
Total deferred charges and other assets	300.4	296.6
TOTAL ASSETS	10,886.2	10,748.6
CURRENT LIABILITIES
Short-term debt	207.5	0
Accounts payable	151.6	239.3
Dividends payable	73	72.9
Customer deposits	83.4	83.6
Accrued taxes	40.8	44
Accrued interest	35.8	44.5
Accrued compensation	33.1	47.8
Long-term debt due within one year	0	250
Fuel clause over recoveries	0.1	0.3
Other	77.4	87
Total current liabilities	702.7	869.4
LONG-TERM DEBT	3,193.6	2,896.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	224.9	225.7
Deferred income taxes	1,325	1,310.9
Deferred investment tax credits	7.2	7.2
Regulatory liabilities	1,243	1,270.7
Other	182.6	162.7
Total deferred credits and other liabilities	2,982.7	2,977.2
Total liabilities	6,879	6,743.5
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,123.4	1,127.7
Retained earnings	2,904.9	2,906.3
Accumulated other comprehensive loss, net of tax	(21.1)	(28.9)
Total stockholders' equity	4,007.2	4,005.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 10,886.2	$ 10,748.6

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Accounts Receivable, Allowance for Credit Loss	$ 1.3	$ 1.7

CONDENSED CONSOLIDATED STATEM_5

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)
Changes in Stockholders' Equity
Common Stock, Shares, Outstanding		199.7
Balance at Dec. 31, 2017	$ 3,851.1	$ 2	$ 1,112.8	$ 2,759.5	$ (23.2)
Changes in Stockholders' Equity
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Net income	55	$ 0	0	55	0
Dividends, Common Stock, Cash, Number of Shares		0
Other comprehensive income net of tax	0.2	$ 0	0	0	0.2
Dividends declared on common stock ($0.3650 per share)	(66.5)	$ 0	0	(66.5)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
Stock-based compensation	2.3	$ 0	2.3	0	0
Balance at Mar. 31, 2018	3,842.1	2	1,115.1	2,748	(23)
Balance at Dec. 31, 2017	3,851.1	2	1,112.8	2,759.5	(23.2)
Changes in Stockholders' Equity
Net income	165.7			165.7
Other comprehensive income net of tax	0.9
Balance at Jun. 30, 2018	3,890.1	$ 2	1,118.1	2,792.3	(22.3)
Changes in Stockholders' Equity
Common Stock, Shares, Outstanding		199.7
Balance at Mar. 31, 2018	3,842.1	$ 2	1,115.1	2,748	(23)
Changes in Stockholders' Equity
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Net income	110.7	$ 0	0	110.7	0
Dividends, Common Stock, Cash, Number of Shares		0
Other comprehensive income net of tax	0.7	$ 0	0	0	0.7
Dividends declared on common stock ($0.3650 per share)	(66.4)	$ 0	0	(66.4)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
Stock-based compensation	3	$ 0	3	0	0
Balance at Jun. 30, 2018	3,890.1	$ 2	1,118.1	2,792.3	(22.3)
Changes in Stockholders' Equity
Common Stock, Shares, Outstanding		199.7
Common Stock, Shares, Outstanding		199.7
Balance at Dec. 31, 2018	4,005.1	$ 2	1,125.7	2,906.3	(28.9)
Changes in Stockholders' Equity
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Net income	47.1	$ 0	0	47.1	0
Dividends, Common Stock, Cash, Number of Shares		0
Other comprehensive income net of tax	6.8	$ 0	0	0	6.8
Dividends declared on common stock ($0.3650 per share)	(75.6)	$ 0	0	(75.6)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0.5
Stock-based compensation	(7.2)	$ 0	(7.2)	0	0
Balance at Mar. 31, 2019	3,976.2	2	1,118.5	2,877.8	(22.1)
Balance at Dec. 31, 2018	4,005.1	2	1,125.7	2,906.3	(28.9)
Changes in Stockholders' Equity
Net income	147.3			147.3
Other comprehensive income net of tax	7.8
Balance at Jun. 30, 2019	4,007.2	$ 2	1,121.4	2,904.9	(21.1)
Changes in Stockholders' Equity
Common Stock, Shares, Outstanding		200.2
Balance at Mar. 31, 2019	3,976.2	$ 2	1,118.5	2,877.8	(22.1)
Changes in Stockholders' Equity
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Net income	100.2	$ 0	0	100.2	0
Dividends, Common Stock, Cash, Number of Shares		0
Other comprehensive income net of tax	1	$ 0	0	0	1
Dividends declared on common stock ($0.3650 per share)	(73.1)	$ 0	0	(73.1)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
Stock-based compensation	2.9	$ 0	2.9	0	0
Balance at Jun. 30, 2019	$ 4,007.2	$ 2	$ 1,121.4	$ 2,904.9	$ (21.1)
Changes in Stockholders' Equity
Common Stock, Shares, Outstanding		200.2

CONDENSED CONSOLIDATED STATEM_6

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Unaudited) Parenthetical - $ / shares	3 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 0.3650	$ 0.3650	$ 0.3325	$ 0.3325

Summary of Significant Accounti

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2019
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 2018 Form 10-K . Changes to the Company's accounting policies as a result of adopting ASU 2016-02, "Leases (Topic 842)," and the related ASU 2018-01 and ASU 2018-11 are discussed in Notes 2 and 4 in this Form 10-Q.
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Organization The Company is a holding company with investments in energy and energy services providers 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 was formed in 2013, and its general partner 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 accounts for its interest in Enable using the equity method of accounting. Enable is primarily 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.
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, 2019 and December 31, 2018 , the consolidated results of its operations for the three and six months ended June 30, 2019 and 2018 and its consolidated cash flows for the six months ended June 30, 2019 and 2018 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, 2019 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, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 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 2018 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) 2019 2018 REGULATORY ASSETS Current: Fuel clause under recoveries $ 30.7 $ 2.0 Cogeneration credit rider over credit (A) 8.2 — Production tax credit rider over credit (A) 4.1 6.9 Oklahoma demand program rider under recovery (A) — 6.4 Other (A) 5.1 3.2 Total current regulatory assets $ 48.1 $ 18.5 Non-current: Benefit obligations regulatory asset $ 172.3 $ 188.2 Deferred storm expenses 43.6 36.5 Smart Grid 22.1 25.6 Sooner Dry Scrubbers 21.0 4.5 Unamortized loss on reacquired debt 11.0 11.4 Arkansas deferred pension expenses 7.7 6.8 Other 12.3 12.8 Total non-current regulatory assets $ 290.0 $ 285.8 REGULATORY LIABILITIES Current: Reserve for tax refund and interim surcharge (B) $ 17.7 $ 15.4 SPP cost tracker over recovery (B) 8.0 16.8 Oklahoma demand program rider over recovery (B) 6.2 — Transmission cost recovery rider over recovery (B) 1.1 2.7 Fuel clause over recoveries 0.1 0.3 Other (B) 3.2 1.4 Total current regulatory liabilities $ 36.3 $ 36.6 Non-current: Income taxes refundable to customers, net $ 921.6 $ 937.1 Accrued removal obligations, net 312.9 308.1 Pension tracker 2.2 18.7 Other 6.3 6.8 Total non-current regulatory liabilities $ 1,243.0 $ 1,270.7 (A) Included in Other Current Assets in the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities in 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, 2019 and 2018 . 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 (Credit) Net Income (Loss) Prior Service Cost (Credit) Total Balance at December 31, 2018 $ (38.8 ) $ — $ 4.6 $ 5.3 $ (28.9 ) Amounts reclassified from accumulated other comprehensive income (loss) 1.7 — (0.1 ) (0.9 ) 0.7 Settlement cost 7.1 — — — 7.1 Balance at June 30, 2019 $ (30.0 ) $ — $ 4.5 $ 4.4 $ (21.1 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net Income Prior Service Cost (Credit) Net Income Prior Service Cost (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 ) 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, 2019 and 2018 . 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) 2019 2018 2019 2018 Amortization of Pension Plan and Restoration of Retirement Income Plan items: Actuarial losses (A) $ (1.3 ) $ (1.3 ) $ (2.2 ) $ (2.2 ) Other Net Periodic Benefit Expense Settlement cost (A) (0.6 ) — (9.4 ) — Other Net Periodic Benefit Expense (1.9 ) (1.3 ) (11.6 ) (2.2 ) Income Before Taxes (0.4 ) (0.3 ) (2.8 ) (0.5 ) Income Tax Expense $ (1.5 ) $ (1.0 ) $ (8.8 ) $ (1.7 ) Net Income Amortization of postretirement benefit plans items: Prior service credit (A) $ 0.5 $ 0.5 $ 1.1 $ 1.1 Other Net Periodic Benefit Expense Actuarial gains (A) 0.1 — 0.1 — Other Net Periodic Benefit Expense 0.6 0.5 1.2 1.1 Income Before Taxes 0.1 0.2 0.2 0.3 Income Tax Expense $ 0.5 $ 0.3 $ 1.0 $ 0.8 Net Income Total reclassifications for the period, net of tax $ (1.0 ) $ (0.7 ) $ (7.8 ) $ (0.9 ) Net Income (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 12 for additional information).
Reclassifications [Text Block]	Reclassifications Certain prior year amounts have been reclassified to conform to the current year presentation.

Accounting Pronouncements

Accounting Pronouncements	6 Months Ended
	Jun. 30, 2019
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 Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between prior 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, 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 is equal to the present value of lease payments. The asset is based on the liability, subject to adjustment for items such as 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 result in straight-line expense, while finance leases result in a front-loaded expense pattern, similar to prior capital leases. Classification of operating and finance leases is based on criteria that are largely similar to those applied in prior lease guidance but without the explicit thresholds. The Company adopted this standard in the first quarter of 2019 utilizing the modified retrospective transition method. Various practical expedients for the application of Topic 842 were approved, and the Company elected to apply the below: • a 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; • an option that 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"; and • an option that permits an entity to 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, provided that if an entity elects this 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. The Company evaluated its current lease contracts and, at January 1, 2019, recognized $34.5 million and $39.1 million of operating lease right-of-use assets and liabilities, respectively, for railcar , wind farm land and office space leases in the Condensed Consolidated Balance Sheet. The new standard did not have a material impact on the Company's 2019 periods within the Condensed Consolidated Statements of Income. Further, the Company evaluated its existing processes and controls regarding lease identification, accounting and presentation and implemented changes as necessary in order to adequately address the requirements of Topic 842. Additional information regarding the Company's adoption of Topic 842 can be found in the Company's 2018 Form 10-K . Issued Accounting Standards Not Yet Adopted Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. In August 2018, the FASB issued ASU 2018-15, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." The new guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. ASU 2018-15 is effective for fiscal years beginning after December 2019 and can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its Condensed Consolidated Financial Statements.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	6 Months Ended
	Jun. 30, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenue Recognition 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" within "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations." Three Months Ended June 30, Six Months Ended June 30, (In millions) 2019 2018 2019 2018 Residential $ 182.3 $ 217.3 $ 373.5 $ 413.5 Commercial 115.4 135.1 210.8 235.9 Industrial 52.9 57.0 105.2 107.4 Oilfield 48.9 45.7 98.3 87.8 Public authorities and street light 44.4 51.1 84.5 92.8 System sales revenues 443.9 506.2 872.3 937.4 Provision for rate refund (0.5 ) (16.5 ) (0.6 ) (19.7 ) Integrated market 10.3 13.1 17.0 21.8 Transmission 39.8 40.2 75.9 76.0 Other 7.6 4.7 13.9 10.1 Revenues from contracts with customers $ 501.1 $ 547.7 $ 978.5 $ 1,025.6

Leases (Notes)

Leases (Notes)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Leases [Text Block]	Leases The Company evaluates all contracts under Topic 842 to determine if the contract is or contains a lease and to determine classification as an operating or finance lease. If a lease is identified, the Company recognizes a right-of-use asset and a lease liability in its Consolidated Balance Sheets. The Company recognizes and measures a lease liability when it concludes the contract contains an identified asset that the Company controls through having the right to obtain substantially all of the economic benefits and the right to direct the use of the identified asset. The liability is equal to the present value of lease payments, and the asset is based on the liability, subject to adjustment, such as for initial direct costs. Further, the Company utilizes an incremental borrowing rate for purposes of measuring lease liabilities, if the discount rate is not implicit in the lease. To calculate the incremental borrowing rate, the Company starts with a current pricing report for the Company's senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjusts for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted by Topic 842, the Company made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from nonlease components when recognizing and measuring lease liabilities. For income statement purposes, the Company records operating lease expense on a straight-line basis. Based on its evaluation of all contracts under Topic 842, as described above, the Company concluded it has operating lease obligations for OG&E railcar leases, OG&E wind farm land leases and the Company's office space lease. Operating Leases OG&E Railcar Lease Agreement Effective February 1, 2019, OG&E renewed a railcar lease agreement for 780 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's fuel adjustment clauses. On February 1, 2024, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $6.8 million . OG&E Wind Farm Land Lease Agreements The Company has operating leases related to land for OG&E's Centennial, OU Spirit and Crossroads wind farms with terms of 25 to 30 years. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. While lease liabilities are not remeasured as a result of changes to the Consumer Price Index, changes to the Consumer Price Index are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their useful life. Office Space Lease The Company has a noncancellable office space lease agreement, with a term from September 1, 2018 to August 31, 2021, that allows for leasehold improvements. Financial Statement Information and Maturity Analysis of Lease Liabilities Operating lease cost was $1.4 million and $3.0 million for the three and six months ended June 30, 2019 , respectively. Payments for operating lease obligations were $4.9 million for the year ended December 31, 2018. The following table presents amounts recognized for operating leases in the Company's 2019 Condensed Consolidated Cash Flow Statement and Balance Sheet and supplemental information related to those amounts recognized, as well as a maturity analysis of the Company's operating lease liabilities. Six Months Ended (In millions) June 30, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 4.1 Right-of-use assets obtained in exchange for new operating lease liabilities $ 10.7 (Dollars in millions) June 30, 2019 Right-of-use assets at period end (A) $ 43.1 Operating lease liabilities at period end (B) $ 47.8 Operating lease weighted-average remaining lease term (in years) 13.3 Operating lease weighted-average discount rate 3.9 % Future minimum operating lease payments as of: ( In millions) June 30, 2019 December 31, 2019 $ 1.7 $ 22.1 2020 6.2 3.9 2021 5.9 3.5 2022 5.2 2.9 2023 5.1 2.9 Thereafter 37.8 37.6 Total future minimum lease payments 61.9 $ 72.9 Less: Imputed interest 14.1 Present value of net minimum lease payments $ 47.8 (A) Included in Property, Plant and Equipment in the 2019 Condensed Consolidated Balance Sheet. (B) Included in Other Deferred Credits and Other Liabilities in the 2019 Condensed Consolidated Balance Sheet. (C) Amounts included for comparability and accounted for in accordance with ASC 840, "Leases." (D) At the end of the railcar lease term, which was February 1, 2019, OG&E had the option to either purchase the railcars at a stipulated fair market value or renew the lease. OG&E renewed the lease effective February 1, 2019. If OG&E chose not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars was less than the stipulated fair market value, OG&E would have been responsible for the difference in those values up to a maximum of $16.2 million .

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	6 Months Ended
	Jun. 30, 2019
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, 2019 as presented in Note 13. 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 In 2013, the Company, CenterPoint and the ArcLight group formed Enable as a private limited partnership, and 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 recorded the contribution at historical cost. 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 was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion . Since the contribution of Enogex LLC to Enable was recorded 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. As prior real estate sales accounting guidance was superseded by ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets," the Company recognizes gains or losses on sales or dilution events in the Company's investment in Enable within the Company's earnings, net of proportional basis difference recognition. At June 30, 2019 , the Company owned 111.0 million common units, or 25.5 percent , of Enable's outstanding common units. On June 28, 2019, Enable's common unit price closed at $13.71 . The Company recorded equity in earnings of unconsolidated affiliates of $35.8 million and $29.3 million for the three months ended June 30, 2019 and 2018 , respectively, and $66.5 million and $63.2 million for the six months ended June 30, 2019 and 2018 , 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, beginning in 2013, over the average life of the assets to which the basis difference is attributed, which is approximately 30 years. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above. These amortizations may also include gain or loss on dilution, net of proportional basis difference recognition. Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2019 and December 31, 2018 and for the three and six months ended June 30, 2019 and 2018 . June 30, December 31, Balance Sheet 2019 2018 (In millions) Current assets $ 376 $ 449 Non-current assets $ 12,033 $ 11,995 Current liabilities $ 1,270 $ 1,615 Non-current liabilities $ 3,580 $ 3,211 Three Months Ended Six Months Ended June 30, June 30, Income Statement 2019 2018 2019 2018 (In millions) Total revenues $ 735 $ 805 $ 1,530 $ 1,553 Cost of natural gas and NGLs $ 317 $ 444 $ 695 $ 819 Operating income $ 167 $ 126 $ 332 $ 265 Net income $ 115 $ 86 $ 228 $ 191 The following table reconciles the Company's equity in earnings of unconsolidated affiliates for the three and six months ended June 30, 2019 and 2018 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Enable net income $ 114.8 $ 86.4 $ 228.0 $ 191.0 Differences due to timing of OGE Energy and Enable accounting close — — 0.1 — Enable net income used to calculate OGE Energy's equity in earnings $ 114.8 $ 86.4 $ 228.1 $ 191.0 OGE Energy's percent ownership at period end 25.5 % 25.6 % 25.5 % 25.6 % OGE Energy's portion of Enable net income $ 29.3 $ 22.2 $ 58.2 $ 49.0 Amortization of basis difference and dilution recognition (A) 6.5 7.1 8.3 14.2 Equity in earnings of unconsolidated affiliates $ 35.8 $ 29.3 $ 66.5 $ 63.2 (A) Includes loss on dilution, net of proportional basis difference recognition . The following table reconciles the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2018 to June 30, 2019 . (In millions) Basis difference at December 31, 2018 $ 680.3 Amortization of basis difference (A) (13.5 ) Basis difference at June 30, 2019 $ 666.8 (A) Includes proportional basis difference recognition due to dilution. On August 2, 2019, Enable announced a quarterly dividend distribution of $0.33050 per unit on its outstanding common units, which is an increase from the previous quarter's dividend distribution of $0.31800 per unit. 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. Distributions received from Enable were $35.3 million and $70.6 million during both the three months ended and both the six months ended June 30, 2019 and 2018 , respectively. Related Party Transactions 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. The Company and Enable 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 $0.1 million and $0.2 million during the three months ended June 30, 2019 and 2018 , respectively, and $0.2 million and $0.3 million during the six months ended June 30, 2019 and 2018 , respectively. Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of June 30, 2019 , 85 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $4.0 million and $5.2 million during the three months ended June 30, 2019 and 2018 , respectively, and $16.4 million and $16.8 million during the six months ended June 30, 2019 and 2018 , 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 $12.0 million . Settlement and curtailment charges associated with the Enable 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 $1.2 million as of June 30, 2019 and $1.7 million as of December 31, 2018 , which are included in Accounts Receivable in the Company's Condensed Consolidated Balance Sheets. OG&E and Enable As discussed in the Company's 2018 Form 10-K , Enable provides gas transportation services to OG&E pursuant to an agreement that 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, 2019 and 2018 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Operating revenues: Electricity to power electric compression assets $ 3.8 $ 3.6 $ 7.6 $ 7.6 Cost of sales: Natural gas transportation services $ 9.3 $ 8.8 $ 24.1 $ 17.5 Natural gas (sales) purchases $ (3.3 ) $ 2.2 $ (4.3 ) $ 2.5

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2019
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, 2019 and December 31, 2018 . 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, 2019 and December 31, 2018 . June 30, December 31, 2019 2018 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year): Senior Notes $ 3,048.6 $ 3,428.0 $ 3,001.9 $ 3,178.2 OG&E Industrial Authority Bonds $ 135.4 $ 135.4 $ 135.4 $ 135.4 Tinker Debt $ 9.6 $ 9.3 $ 9.6 $ 8.7

Stock-Based Compensation

Stock-Based Compensation	6 Months Ended
	Jun. 30, 2019
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement [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, 2019 and 2018 related to the Company's performance units and restricted stock . Three Months Ended June 30, Six Months Ended June 30, (In millions) 2019 2018 2019 2018 Performance units: Total shareholder return $ 2.3 $ 2.1 $ 4.5 $ 4.1 Earnings per share 0.4 1.0 0.9 1.7 Total performance units 2.7 3.1 5.4 5.8 Restricted stock 0.2 — 0.5 — Total compensation expense $ 2.9 $ 3.1 $ 5.9 $ 5.8 Income tax benefit $ 0.7 $ 0.8 $ 1.5 $ 1.5 During the three and six months ended June 30, 2019 , the Company issued an immaterial amount of shares and 443,497 shares, respectively, 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, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company files consolidated income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local tax examinations by tax authorities for years prior to 2015 . 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 will be 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, 2019
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, 2019 . 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) 2019 2018 2019 2018 Net income $ 100.2 $ 110.7 $ 147.3 $ 165.7 Average common shares outstanding: Basic average common shares outstanding 200.2 199.7 200.1 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.4 0.8 0.4 0.6 Diluted average common shares outstanding 200.6 200.5 200.5 200.3 Basic earnings per average common share $ 0.50 $ 0.55 $ 0.74 $ 0.83 Diluted earnings per average common share $ 0.50 $ 0.55 $ 0.73 $ 0.83 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2019
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	Long-Term Debt At June 30, 2019 , 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) 1.46% - 2.50% Garfield Industrial Authority, January 1, 2025 $ 47.0 1.43% - 2.35% Muskogee Industrial Authority, January 1, 2025 32.4 1.45% - 2.48% 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 Balance Sheets. OG&E believes that it has sufficient liquidity to meet these obligations. Issuance of Long-Term Debt In June 2019, OG&E issued $300.0 million of 3.30 percent senior notes due March 15, 2030 . The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to repay short-term debt (including debt pertaining to the acquisition of the River Valley plant) and to fund ongoing capital expenditures and working capital.

Short-Term Debt and Credit Faci

Short-Term Debt and Credit Facilities	6 Months Ended
	Jun. 30, 2019
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, 2019 , the Company had $207.5 million of short-term debt as compared to no short-term debt at December 31, 2018 . The following table provides information regarding the Company's revolving credit agreements at June 30, 2019 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ 207.5 2.63 % (D) March 8, 2023 OG&E (C) 450.0 0.3 1.15 % (D) March 8, 2023 Total $ 900.0 $ 207.8 2.63 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2019 . (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. 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, 2019 and ending December 31, 2020.

Retirement Plans and Postretire

Retirement Plans and Postretirement Benefit Plans	6 Months Ended
	Jun. 30, 2019
Defined Benefit Plan [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Retirement Plans and Postretirement Benefit Plans In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during the plan year exceed the service cost and interest cost components of the organization's net periodic pension cost. During the first six months of 2019, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement, which resulted in the Company recording a pension settlement charge of $20.6 million . The pension settlement charge did not require a cash outlay by the Company and did not increase the Company's total pension expense over time, as the charge was an acceleration of costs that otherwise would be recognized as pension expense in future periods. Net Periodic Benefit Cost The following table presents 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, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in the Company's Condensed Consolidated Statements of Income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Expense in 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) 2019 2018 2019 2018 2019 2018 2019 2018 Service cost $ 2.8 $ 3.4 $ 6.3 $ 7.5 $ 0.1 $ 0.1 $ 0.2 $ 0.2 Interest cost 5.2 5.8 10.9 11.7 0.1 0.1 0.2 0.2 Expected return on plan assets (8.9 ) (11.0 ) (17.6 ) (22.3 ) — — — — Amortization of net loss 4.8 4.4 8.6 8.3 0.1 0.3 0.2 0.4 Settlement cost 0.9 — 20.6 — — — — — Total net periodic benefit cost 4.8 2.6 28.8 5.2 0.3 0.5 0.6 0.8 Less: Amount paid by unconsolidated affiliates 0.8 0.7 1.7 1.2 — — — — Net periodic benefit cost $ 4.0 $ 1.9 $ 27.1 $ 4.0 $ 0.3 $ 0.5 $ 0.6 $ 0.8 (A) In addition to the $4.3 million and $2.4 million of net periodic benefit cost recognized during the three months ended June 30, 2019 and 2018 , respectively , the Company recognized a decrease of pension expense of $0.7 million and an increase of $3.8 million during the three months ended June 30, 2019 and 2018 , 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) . (B) In addition to the $27.7 million and $4.8 million of net periodic benefit cost recognized during the six months ended June 30, 2019 and 2018 , respectively , the Company recognized the following: • a decrease of pension expense of $1.7 million and an increase of $7.8 million during the six months ended June 30, 2019 and 2018 , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1) ; • a deferral of pension expense during the six months ended June 30, 2019 of $11.7 million related to the pension settlement charge of $20.6 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the six months ended June 30, 2019 of $1.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $20.6 million (see Note 1). Postretirement Benefit Plans Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Service cost $ — $ 0.1 $ 0.1 $ 0.2 Interest cost 1.4 1.3 2.8 2.6 Expected return on plan assets (0.4 ) (0.5 ) (0.9 ) (1.0 ) Amortization of net loss 0.4 0.9 1.0 1.9 Amortization of unrecognized prior service cost (A) (2.1 ) (2.1 ) (4.2 ) (4.2 ) Total net periodic benefit cost (0.7 ) (0.3 ) (1.2 ) (0.5 ) Less: Amount paid by unconsolidated affiliates (0.1 ) (0.1 ) (0.3 ) (0.2 ) Net periodic benefit cost $ (0.6 ) $ (0.2 ) $ (0.9 ) $ (0.3 ) (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 $0.6 million and $0.2 million of net periodic benefit income recognized during the three months ended June 30, 2019 and 2018 , respectively, the Company recognized an increase in postretirement medical expense during the three months ended June 30, 2019 and 2018 of $0.5 million and $2.2 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 $0.9 million and $0.3 million of net periodic benefit income recognized during the six months ended June 30, 2019 and 2018 , respectively, the Company recognized an increase in postretirement medical expense during the six months ended June 30, 2019 and 2018 of $0.8 million and $4.3 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1). Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Capitalized portion of net periodic pension benefit cost $ 0.8 $ 0.9 $ 1.8 $ 1.9 Capitalized portion of net periodic postretirement benefit cost $ — $ 0.1 $ 0.1 $ 0.1

Report of Business Segments

Report of Business Segments	6 Months Ended
	Jun. 30, 2019
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, 2019 and 2018 . Three Months Ended June 30, 2019 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 513.7 $ — $ — $ — $ 513.7 Cost of sales 178.7 — — — 178.7 Other operation and maintenance 120.0 0.3 (0.5 ) — 119.8 Depreciation and amortization 84.3 — — — 84.3 Taxes other than income 20.1 0.1 0.7 — 20.9 Operating income (loss) 110.6 (0.4 ) (0.2 ) — 110.0 Equity in earnings of unconsolidated affiliates — 35.8 — — 35.8 Other income (expense) 1.5 (0.4 ) 1.0 (0.6 ) 1.5 Interest expense 33.3 — 3.2 (0.6 ) 35.9 Income tax expense (benefit) 4.3 8.1 (1.2 ) — 11.2 Net income (loss) $ 74.5 $ 26.9 $ (1.2 ) $ — $ 100.2 Investment in unconsolidated affiliates $ — $ 1,157.2 $ 14.1 $ — $ 1,171.3 Total assets $ 9,733.8 $ 1,160.0 $ 104.5 $ (112.1 ) $ 10,886.2 Three Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 567.0 $ — $ — $ — $ 567.0 Cost of sales 208.7 — — — 208.7 Other operation and maintenance 117.5 0.3 (0.6 ) — 117.2 Depreciation and amortization 80.9 — — — 80.9 Taxes other than income 21.6 0.2 0.7 — 22.5 Operating income (loss) 138.3 (0.5 ) (0.1 ) — 137.7 Equity in earnings of unconsolidated affiliates — 29.3 — — 29.3 Other income (expense) 4.0 — (0.6 ) (0.9 ) 2.5 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 Six Months Ended June 30, 2019 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 1,003.7 $ — $ — $ — $ 1,003.7 Cost of sales 391.3 — — — 391.3 Other operation and maintenance 240.3 0.7 (2.2 ) — 238.8 Depreciation and amortization 166.7 — — — 166.7 Taxes other than income 44.5 0.3 2.4 — 47.2 Operating income (loss) 160.9 (1.0 ) (0.2 ) — 159.7 Equity in earnings of unconsolidated affiliates — 66.5 — — 66.5 Other income (expense) 4.1 (7.8 ) 1.7 (1.0 ) (3.0 ) Interest expense 65.7 — 5.8 (1.0 ) 70.5 Income tax expense (benefit) 5.2 9.5 (9.3 ) — 5.4 Net income $ 94.1 $ 48.2 $ 5.0 $ — $ 147.3 Investment in unconsolidated affiliates $ — $ 1,157.2 $ 14.1 $ — $ 1,171.3 Total assets $ 9,733.8 $ 1,160.0 $ 104.5 $ (112.1 ) $ 10,886.2 Six Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 1,059.7 $ — $ — $ — $ 1,059.7 Cost of sales 419.2 — — — 419.2 Other operation and maintenance 231.1 0.6 (1.8 ) — 229.9 Depreciation and amortization 159.7 — — — 159.7 Taxes other than income 44.3 0.4 1.9 — 46.6 Operating income (loss) 205.4 (1.0 ) (0.1 ) — 204.3 Equity in earnings of unconsolidated affiliates — 63.2 — — 63.2 Other income (expense) 8.5 — (1.3 ) (1.5 ) 5.7 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

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2019
Long-term Purchase Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingencies Except as set forth below, in Note 15 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 14 and 15 to the Consolidated Financial Statements included in the Company's 2018 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities. Public Utility Regulatory Policy Act of 1978 As previously disclosed in the Company's 2018 Form 10-K , OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019. For this 120 MW contract, OG&E purchases 100 percent of the electricity generated. OG&E also had a 320 MW contract with AES that expired on January 15, 2019, through which OG&E purchased 100 percent of the electricity generated. In December 2018, OG&E announced its plan to acquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to meet customers' energy needs. In May 2019, OG&E received the necessary approval from the OCC and the FERC and conditional approval from the APSC to acquire both plants. In May 2019, OG&E acquired the power plant from AES and expects to acquire the plant from Oklahoma Cogeneration LLC in the third quarter of 2019. Further discussion can be found in Note 15. 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. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. 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 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, 2019
Regulated Operations [Abstract]
Rate Matters and Regulation	Rate Matters and Regulation Except as set forth below, the circumstances set forth in Note 15 to the Consolidated Financial Statements included in the Company's 2018 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. Completed Regulatory Matters Arkansas Formula Rate Plan Filing Per OG&E's settlement in its last general rate review, OG&E filed an evaluation report under its Formula Rate Plan in October 2018. On March 6, 2019, the APSC approved a settlement agreement for a $3.3 million revenue increase, and new rates were effective as of April 1, 2019. OCC and FERC Approval for Acquisition of Existing Power Plants In December 2018, OG&E filed an application for pre-approval from the OCC to acquire a 360 MW capacity coal- and natural gas-fired plant from AES and a 146 MW capacity natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC in 2019 for $53.5 million . The purchase of these assets replaces capacity provided by purchased power contracts that have expired or are expiring in 2019 and helps OG&E satisfy its customers' energy needs and load obligations to the SPP. In addition, the filing sought approval of a rider mechanism to collect costs associated with the purchase of these generating facilities. On May 13, 2019, the OCC approved OG&E's acquisition of both plants, the requested rider mechanism for the AES plant and regulatory asset treatment for the Oklahoma Cogeneration LLC plant that will defer non-fuel operation and maintenance expenses, depreciation and ad valorem taxes. On January 23, 2019, OG&E filed an application for Federal Power Act Section 203 approval with a request for expedited consideration. This application requested FERC's prior authorization to acquire the AES and Oklahoma Cogeneration LLC plants. On May 22, 2019, OG&E received authorization from the FERC to acquire both plants. In May 2019, OG&E completed the acquisition of the power plant from AES and placed it into service, which is now named the River Valley power plant. Closing for the acquisition of the power plant from Oklahoma Cogeneration LLC is anticipated during the third quarter of 2019. Fuel Adjustment Clause Review for Calendar Year 2017 In July 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. On February 1, 2019, the ALJ recommended that OG&E's processes, costs, investments and decisions regarding fuel procurement for the 2017 calendar year be found prudent. On May 22, 2019, the OCC deemed OG&E's electric generation, purchased power and fuel procurement costs to be materially prudent. 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. 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. 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. In May 2019, all parties agreed to a settlement which provides for 10 percent base return on equity, plus a 50-basis point adder, and a five-year amortization period of the unprotected excess accumulated deferred income taxes associated with the 2017 Tax Act. While pending approval by the FERC, interim rates are currently being applied by the SPP pursuant to the terms of the settlement agreement. Oklahoma Rate Review Filing - December 2018 In December 2018, OG&E filed a general rate review with the OCC, requesting a rate increase of $77.6 million per year to recover its investment in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas. The filing also sought to align OG&E's return on equity more closely to the industry average and to align OG&E's depreciation rates to more realistically reflect its assets' lifespans. On May 24, 2019, OG&E entered into a non-unanimous joint stipulation and settlement agreement with the OCC staff, the Attorney General's Office of Oklahoma, the Oklahoma Industrial Energy Consumers and other certain parties associated with the requested rate increase. The filing was further amended on May 30, 2019 to include Oklahoma Association of Electric Cooperatives as a settling party. The settlement is subject to OCC approval. Under the terms of the settlement agreement, OG&E would receive full recovery of its environmental investments in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas. Base rates would not change as a result of the settlement agreement due to the reduction of costs related to cogeneration contracts and the acceleration of unprotected deferred tax savings over a 10-year period. Further, OG&E's current depreciation rates and return on equity of 9.5 percent for purposes of calculating the allowance for funds used during construction and OG&E's various recovery riders that include a full return component would remain unchanged. On July 1, 2019, OG&E implemented interim rates, which are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate review. On July 12, 2019, the ALJ issued a report that recommended approval of the settlement agreement and found the settlement agreement fair, just, reasonable and in the public interest. The ALJ's report also recommended that OG&E's environmental compliance decisions and costs related to the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas be found prudent and used and useful with cost recovery allowed. These recommendations are subject to approval by the OCC. A hearing on exceptions was held on August 6, 2019, and OG&E is awaiting a final order from the OCC. The Dry Scrubbers project, which includes the installation of two dry scrubbers at the Sooner plant, and the conversion of Muskogee Units 4 and 5 to natural gas were initiated in response to the EPA's MATS and Regional Haze Rule FIP. The Dry Scrubber systems on Sooner Unit 1 and Unit 2 were placed into service in October 2018 and January 2019, respectively. Muskogee Units 4 and 5 were placed into service in March 2019. As of June 30, 2019 , OG&E has invested $512.4 million in the Dry Scrubbers and $57.0 million in the Muskogee natural gas conversion. FERC Order for Sponsored Transmission Upgrades within SPP Under the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades due to information system limitations. However, SPP had informed participants in the market that these charges would be forthcoming. In July 2016, the FERC granted SPP's request to recover the charges not billed since 2008. SPP subsequently billed OG&E for these charges and credited OG&E related to transmission upgrades that OG&E had sponsored, which resulted in OG&E being a net receiver of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E. Several impacted companies sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia. In July 2018, the U.S. Court of Appeals for the District of Columbia granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and ordered SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, on April 1, 2019, OG&E filed a request for rehearing with the FERC, and on May 24, 2019, OG&E filed a FERC 206 complaint against SPP, alleging SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement. OG&E's filing requested that the FERC rule that SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. The Company cannot predict the outcome of this proceeding based on currently available information, and as of June 30, 2019 and at present time, the Company has not reserved an amount for a potential refund. If the reversal of the July 2016 FERC order remains intact, OG&E estimates it would be required to refund $13.0 million , which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. If refunds were required, recovery of these upgrade credits would shift to future periods. Of the $13.0 million , the Company would be impacted by $5.0 million in expense that initially benefited the Company in 2016, and OG&E customers would incur a net impact of $8.0 million in expense through rider mechanisms or the FERC formula rate. Fuel Adjustment Clause Review for Calendar Year 2018 In June 2019, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2018, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. APSC - Environmental Compliance Plan Rider On May 31, 2019, OG&E filed an environmental compliance plan rider in Arkansas to recover its investment for the environmentally mandated costs associated with the Dry Scrubbers project and the conversion of Muskogee Units 4 and 5 to natural gas. The filing is an interim surcharge, subject to refund, that began with the first billing cycle of June 2019. OG&E is reserving the amounts collected through the interim surcharge, pending APSC approval of OG&E's filing. APSC Approval for Acquisition of Existing Power Plants On April 24, 2019, OG&E filed an application with the APSC requesting approval of the acquisition, as well as depreciation rates, of the AES and Oklahoma Cogeneration LLC plants, and on May 8, 2019, OG&E received conditional approval for the purchase of the generating facilities. Issues related to depreciation rates and prudence of action will continue to be addressed in the existing docket. Issues regarding prudence of cost may be addressed in the existing docket or in the Formula Rate Plan.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended	6 Months Ended
	Mar. 31, 2019	Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation, Policy [Policy Text Block]		Organization The Company is a holding company with investments in energy and energy services providers 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 was formed in 2013, and its general partner 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 accounts for its interest in Enable using the equity method of accounting. Enable is primarily 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.
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, 2019 and December 31, 2018 , the consolidated results of its operations for the three and six months ended June 30, 2019 and 2018 and its consolidated cash flows for the six months ended June 30, 2019 and 2018 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, 2019 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, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 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
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]	The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable was formed in 2013, and its general partner 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 accounts for its interest in Enable using the equity method of accounting. Enable is primarily 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 in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns crude oil gathering assets in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.	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, 2019 as presented in Note 13. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable, which do not exceed cumulative equity in earnings subsequent to the date of investment, to be a return on investment and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.
Fair Value of Financial Instruments, Policy [Policy Text Block]		The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1), and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). The Company had no financial instruments measured at fair value on a recurring basis at June 30, 2019 and December 31, 2018 . 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 will be 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

Leases (Policies)

Leases (Policies)	6 Months Ended
	Jun. 30, 2019
Leases [Abstract]
Lessee, Leases [Policy Text Block]	The Company evaluates all contracts under Topic 842 to determine if the contract is or contains a lease and to determine classification as an operating or finance lease. If a lease is identified, the Company recognizes a right-of-use asset and a lease liability in its Consolidated Balance Sheets. The Company recognizes and measures a lease liability when it concludes the contract contains an identified asset that the Company controls through having the right to obtain substantially all of the economic benefits and the right to direct the use of the identified asset. The liability is equal to the present value of lease payments, and the asset is based on the liability, subject to adjustment, such as for initial direct costs. Further, the Company utilizes an incremental borrowing rate for purposes of measuring lease liabilities, if the discount rate is not implicit in the lease. To calculate the incremental borrowing rate, the Company starts with a current pricing report for the Company's senior unsecured notes, which indicates rates for periods reflective of the lease term, and adjusts for the effects of collateral to arrive at the secured incremental borrowing rate. As permitted by Topic 842, the Company made an accounting policy election to not apply the balance sheet recognition requirements to short-term leases and to not separate lease components from nonlease components when recognizing and measuring lease liabilities. For income statement purposes, the Company records operating lease expense on a straight-line basis.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2019
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) 2019 2018 REGULATORY ASSETS Current: Fuel clause under recoveries $ 30.7 $ 2.0 Cogeneration credit rider over credit (A) 8.2 — Production tax credit rider over credit (A) 4.1 6.9 Oklahoma demand program rider under recovery (A) — 6.4 Other (A) 5.1 3.2 Total current regulatory assets $ 48.1 $ 18.5 Non-current: Benefit obligations regulatory asset $ 172.3 $ 188.2 Deferred storm expenses 43.6 36.5 Smart Grid 22.1 25.6 Sooner Dry Scrubbers 21.0 4.5 Unamortized loss on reacquired debt 11.0 11.4 Arkansas deferred pension expenses 7.7 6.8 Other 12.3 12.8 Total non-current regulatory assets $ 290.0 $ 285.8 REGULATORY LIABILITIES Current: Reserve for tax refund and interim surcharge (B) $ 17.7 $ 15.4 SPP cost tracker over recovery (B) 8.0 16.8 Oklahoma demand program rider over recovery (B) 6.2 — Transmission cost recovery rider over recovery (B) 1.1 2.7 Fuel clause over recoveries 0.1 0.3 Other (B) 3.2 1.4 Total current regulatory liabilities $ 36.3 $ 36.6 Non-current: Income taxes refundable to customers, net $ 921.6 $ 937.1 Accrued removal obligations, net 312.9 308.1 Pension tracker 2.2 18.7 Other 6.3 6.8 Total non-current regulatory liabilities $ 1,243.0 $ 1,270.7 (A) Included in Other Current Assets in the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities in 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, 2019 and 2018 . 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 (Credit) Net Income (Loss) Prior Service Cost (Credit) Total Balance at December 31, 2018 $ (38.8 ) $ — $ 4.6 $ 5.3 $ (28.9 ) Amounts reclassified from accumulated other comprehensive income (loss) 1.7 — (0.1 ) (0.9 ) 0.7 Settlement cost 7.1 — — — 7.1 Balance at June 30, 2019 $ (30.0 ) $ — $ 4.5 $ 4.4 $ (21.1 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net Income Prior Service Cost (Credit) Net Income Prior Service Cost (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 )
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, 2019 and 2018 . 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) 2019 2018 2019 2018 Amortization of Pension Plan and Restoration of Retirement Income Plan items: Actuarial losses (A) $ (1.3 ) $ (1.3 ) $ (2.2 ) $ (2.2 ) Other Net Periodic Benefit Expense Settlement cost (A) (0.6 ) — (9.4 ) — Other Net Periodic Benefit Expense (1.9 ) (1.3 ) (11.6 ) (2.2 ) Income Before Taxes (0.4 ) (0.3 ) (2.8 ) (0.5 ) Income Tax Expense $ (1.5 ) $ (1.0 ) $ (8.8 ) $ (1.7 ) Net Income Amortization of postretirement benefit plans items: Prior service credit (A) $ 0.5 $ 0.5 $ 1.1 $ 1.1 Other Net Periodic Benefit Expense Actuarial gains (A) 0.1 — 0.1 — Other Net Periodic Benefit Expense 0.6 0.5 1.2 1.1 Income Before Taxes 0.1 0.2 0.2 0.3 Income Tax Expense $ 0.5 $ 0.3 $ 1.0 $ 0.8 Net Income Total reclassifications for the period, net of tax $ (1.0 ) $ (0.7 ) $ (7.8 ) $ (0.9 ) Net Income (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 12 for additional information).

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	6 Months Ended
	Jun. 30, 2019
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" within "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations." Three Months Ended June 30, Six Months Ended June 30, (In millions) 2019 2018 2019 2018 Residential $ 182.3 $ 217.3 $ 373.5 $ 413.5 Commercial 115.4 135.1 210.8 235.9 Industrial 52.9 57.0 105.2 107.4 Oilfield 48.9 45.7 98.3 87.8 Public authorities and street light 44.4 51.1 84.5 92.8 System sales revenues 443.9 506.2 872.3 937.4 Provision for rate refund (0.5 ) (16.5 ) (0.6 ) (19.7 ) Integrated market 10.3 13.1 17.0 21.8 Transmission 39.8 40.2 75.9 76.0 Other 7.6 4.7 13.9 10.1 Revenues from contracts with customers $ 501.1 $ 547.7 $ 978.5 $ 1,025.6

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2019
Operating Leases [Abstract]
Lease, Cost [Table Text Block]	(A) Included in Property, Plant and Equipment in the 2019 Condensed Consolidated Balance Sheet. (B) Included in Other Deferred Credits and Other Liabilities in the 2019 Condensed Consolidated Balance Sheet. The following table presents amounts recognized for operating leases in the Company's 2019 Condensed Consolidated Cash Flow Statement and Balance Sheet and supplemental information related to those amounts recognized, as well as a maturity analysis of the Company's operating lease liabilities. Six Months Ended (In millions) June 30, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 4.1 Right-of-use assets obtained in exchange for new operating lease liabilities $ 10.7 (Dollars in millions) June 30, 2019 Right-of-use assets at period end (A) $ 43.1 Operating lease liabilities at period end (B) $ 47.8 Operating lease weighted-average remaining lease term (in years) 13.3 Operating lease weighted-average discount rate 3.9 %
Operating Lease Payments Due [Table Text Block]	Future minimum operating lease payments as of: ( In millions) June 30, 2019 December 31, 2019 $ 1.7 $ 22.1 2020 6.2 3.9 2021 5.9 3.5 2022 5.2 2.9 2023 5.1 2.9 Thereafter 37.8 37.6 Total future minimum lease payments 61.9 $ 72.9 Less: Imputed interest 14.1 Present value of net minimum lease payments $ 47.8 (C) Amounts included for comparability and accounted for in accordance with ASC 840, "Leases." (D) At the end of the railcar lease term, which was February 1, 2019, OG&E had the option to either purchase the railcars at a stipulated fair market value or renew the lease. OG&E renewed the lease effective February 1, 2019. If OG&E chose not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars was less than the stipulated fair market value, OG&E would have been responsible for the difference in those values up to a maximum of $16.2 million .

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliates (Tables)	6 Months Ended
	Jun. 30, 2019
Reconciliation of Basis Difference [Line Items]
Reconciliation of Basis Difference [Table Text Block]	The following table reconciles the difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable (basis difference) from December 31, 2018 to June 30, 2019 . (In millions) Basis difference at December 31, 2018 $ 680.3 Amortization of basis difference (A) (13.5 ) Basis difference at June 30, 2019 $ 666.8 (A) Includes proportional basis difference recognition due to dilution.
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, 2019 and 2018 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Enable net income $ 114.8 $ 86.4 $ 228.0 $ 191.0 Differences due to timing of OGE Energy and Enable accounting close — — 0.1 — Enable net income used to calculate OGE Energy's equity in earnings $ 114.8 $ 86.4 $ 228.1 $ 191.0 OGE Energy's percent ownership at period end 25.5 % 25.6 % 25.5 % 25.6 % OGE Energy's portion of Enable net income $ 29.3 $ 22.2 $ 58.2 $ 49.0 Amortization of basis difference and dilution recognition (A) 6.5 7.1 8.3 14.2 Equity in earnings of unconsolidated affiliates $ 35.8 $ 29.3 $ 66.5 $ 63.2 (A) Includes loss on dilution, net of proportional basis difference recognition .
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, 2019 and 2018 . Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Operating revenues: Electricity to power electric compression assets $ 3.8 $ 3.6 $ 7.6 $ 7.6 Cost of sales: Natural gas transportation services $ 9.3 $ 8.8 $ 24.1 $ 17.5 Natural gas (sales) purchases $ (3.3 ) $ 2.2 $ (4.3 ) $ 2.5
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, 2019 and December 31, 2018 and for the three and six months ended June 30, 2019 and 2018 . June 30, December 31, Balance Sheet 2019 2018 (In millions) Current assets $ 376 $ 449 Non-current assets $ 12,033 $ 11,995 Current liabilities $ 1,270 $ 1,615 Non-current liabilities $ 3,580 $ 3,211
Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]	Three Months Ended Six Months Ended June 30, June 30, Income Statement 2019 2018 2019 2018 (In millions) Total revenues $ 735 $ 805 $ 1,530 $ 1,553 Cost of natural gas and NGLs $ 317 $ 444 $ 695 $ 819 Operating income $ 167 $ 126 $ 332 $ 265 Net income $ 115 $ 86 $ 228 $ 191

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 and December 31, 2018 . June 30, December 31, 2019 2018 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year): Senior Notes $ 3,048.6 $ 3,428.0 $ 3,001.9 $ 3,178.2 OG&E Industrial Authority Bonds $ 135.4 $ 135.4 $ 135.4 $ 135.4 Tinker Debt $ 9.6 $ 9.3 $ 9.6 $ 8.7

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Cost 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, 2019 and 2018 related to the Company's performance units and restricted stock . Three Months Ended June 30, Six Months Ended June 30, (In millions) 2019 2018 2019 2018 Performance units: Total shareholder return $ 2.3 $ 2.1 $ 4.5 $ 4.1 Earnings per share 0.4 1.0 0.9 1.7 Total performance units 2.7 3.1 5.4 5.8 Restricted stock 0.2 — 0.5 — Total compensation expense $ 2.9 $ 3.1 $ 5.9 $ 5.8 Income tax benefit $ 0.7 $ 0.8 $ 1.5 $ 1.5

Common Equity (Tables)

Common Equity (Tables)	6 Months Ended
	Jun. 30, 2019
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) 2019 2018 2019 2018 Net income $ 100.2 $ 110.7 $ 147.3 $ 165.7 Average common shares outstanding: Basic average common shares outstanding 200.2 199.7 200.1 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.4 0.8 0.4 0.6 Diluted average common shares outstanding 200.6 200.5 200.5 200.3 Basic earnings per average common share $ 0.50 $ 0.55 $ 0.74 $ 0.83 Diluted earnings per average common share $ 0.50 $ 0.55 $ 0.73 $ 0.83 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2019
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) 1.46% - 2.50% Garfield Industrial Authority, January 1, 2025 $ 47.0 1.43% - 2.35% Muskogee Industrial Authority, January 1, 2025 32.4 1.45% - 2.48% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4

Short-Term Debt and Credit Fa_2

Short-Term Debt and Credit Facilities (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ 207.5 2.63 % (D) March 8, 2023 OG&E (C) 450.0 0.3 1.15 % (D) March 8, 2023 Total $ 900.0 $ 207.8 2.63 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2019 . (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.

Retirement Plans and Postreti_2

Retirement Plans and Postretirement Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2019
Defined Benefit Plan [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following table presents 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, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in the Company's Condensed Consolidated Statements of Income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Expense in 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) 2019 2018 2019 2018 2019 2018 2019 2018 Service cost $ 2.8 $ 3.4 $ 6.3 $ 7.5 $ 0.1 $ 0.1 $ 0.2 $ 0.2 Interest cost 5.2 5.8 10.9 11.7 0.1 0.1 0.2 0.2 Expected return on plan assets (8.9 ) (11.0 ) (17.6 ) (22.3 ) — — — — Amortization of net loss 4.8 4.4 8.6 8.3 0.1 0.3 0.2 0.4 Settlement cost 0.9 — 20.6 — — — — — Total net periodic benefit cost 4.8 2.6 28.8 5.2 0.3 0.5 0.6 0.8 Less: Amount paid by unconsolidated affiliates 0.8 0.7 1.7 1.2 — — — — Net periodic benefit cost $ 4.0 $ 1.9 $ 27.1 $ 4.0 $ 0.3 $ 0.5 $ 0.6 $ 0.8 (A) In addition to the $4.3 million and $2.4 million of net periodic benefit cost recognized during the three months ended June 30, 2019 and 2018 , respectively , the Company recognized a decrease of pension expense of $0.7 million and an increase of $3.8 million during the three months ended June 30, 2019 and 2018 , 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) . (B) In addition to the $27.7 million and $4.8 million of net periodic benefit cost recognized during the six months ended June 30, 2019 and 2018 , respectively , the Company recognized the following: • a decrease of pension expense of $1.7 million and an increase of $7.8 million during the six months ended June 30, 2019 and 2018 , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1) ; • a deferral of pension expense during the six months ended June 30, 2019 of $11.7 million related to the pension settlement charge of $20.6 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the six months ended June 30, 2019 of $1.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $20.6 million (see Note 1). Postretirement Benefit Plans Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Service cost $ — $ 0.1 $ 0.1 $ 0.2 Interest cost 1.4 1.3 2.8 2.6 Expected return on plan assets (0.4 ) (0.5 ) (0.9 ) (1.0 ) Amortization of net loss 0.4 0.9 1.0 1.9 Amortization of unrecognized prior service cost (A) (2.1 ) (2.1 ) (4.2 ) (4.2 ) Total net periodic benefit cost (0.7 ) (0.3 ) (1.2 ) (0.5 ) Less: Amount paid by unconsolidated affiliates (0.1 ) (0.1 ) (0.3 ) (0.2 ) Net periodic benefit cost $ (0.6 ) $ (0.2 ) $ (0.9 ) $ (0.3 ) (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 $0.6 million and $0.2 million of net periodic benefit income recognized during the three months ended June 30, 2019 and 2018 , respectively, the Company recognized an increase in postretirement medical expense during the three months ended June 30, 2019 and 2018 of $0.5 million and $2.2 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 $0.9 million and $0.3 million of net periodic benefit income recognized during the six months ended June 30, 2019 and 2018 , respectively, the Company recognized an increase in postretirement medical expense during the six months ended June 30, 2019 and 2018 of $0.8 million and $4.3 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1).
Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]	Three Months Ended Six Months Ended June 30, June 30, (In millions) 2019 2018 2019 2018 Capitalized portion of net periodic pension benefit cost $ 0.8 $ 0.9 $ 1.8 $ 1.9 Capitalized portion of net periodic postretirement benefit cost $ — $ 0.1 $ 0.1 $ 0.1

Report of Business Segments (Ta

Report of Business Segments (Tables)	6 Months Ended
	Jun. 30, 2019
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, 2019 and 2018 . Three Months Ended June 30, 2019 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 513.7 $ — $ — $ — $ 513.7 Cost of sales 178.7 — — — 178.7 Other operation and maintenance 120.0 0.3 (0.5 ) — 119.8 Depreciation and amortization 84.3 — — — 84.3 Taxes other than income 20.1 0.1 0.7 — 20.9 Operating income (loss) 110.6 (0.4 ) (0.2 ) — 110.0 Equity in earnings of unconsolidated affiliates — 35.8 — — 35.8 Other income (expense) 1.5 (0.4 ) 1.0 (0.6 ) 1.5 Interest expense 33.3 — 3.2 (0.6 ) 35.9 Income tax expense (benefit) 4.3 8.1 (1.2 ) — 11.2 Net income (loss) $ 74.5 $ 26.9 $ (1.2 ) $ — $ 100.2 Investment in unconsolidated affiliates $ — $ 1,157.2 $ 14.1 $ — $ 1,171.3 Total assets $ 9,733.8 $ 1,160.0 $ 104.5 $ (112.1 ) $ 10,886.2 Three Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 567.0 $ — $ — $ — $ 567.0 Cost of sales 208.7 — — — 208.7 Other operation and maintenance 117.5 0.3 (0.6 ) — 117.2 Depreciation and amortization 80.9 — — — 80.9 Taxes other than income 21.6 0.2 0.7 — 22.5 Operating income (loss) 138.3 (0.5 ) (0.1 ) — 137.7 Equity in earnings of unconsolidated affiliates — 29.3 — — 29.3 Other income (expense) 4.0 — (0.6 ) (0.9 ) 2.5 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 Six Months Ended June 30, 2019 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 1,003.7 $ — $ — $ — $ 1,003.7 Cost of sales 391.3 — — — 391.3 Other operation and maintenance 240.3 0.7 (2.2 ) — 238.8 Depreciation and amortization 166.7 — — — 166.7 Taxes other than income 44.5 0.3 2.4 — 47.2 Operating income (loss) 160.9 (1.0 ) (0.2 ) — 159.7 Equity in earnings of unconsolidated affiliates — 66.5 — — 66.5 Other income (expense) 4.1 (7.8 ) 1.7 (1.0 ) (3.0 ) Interest expense 65.7 — 5.8 (1.0 ) 70.5 Income tax expense (benefit) 5.2 9.5 (9.3 ) — 5.4 Net income $ 94.1 $ 48.2 $ 5.0 $ — $ 147.3 Investment in unconsolidated affiliates $ — $ 1,157.2 $ 14.1 $ — $ 1,171.3 Total assets $ 9,733.8 $ 1,160.0 $ 104.5 $ (112.1 ) $ 10,886.2 Six Months Ended June 30, 2018 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 1,059.7 $ — $ — $ — $ 1,059.7 Cost of sales 419.2 — — — 419.2 Other operation and maintenance 231.1 0.6 (1.8 ) — 229.9 Depreciation and amortization 159.7 — — — 159.7 Taxes other than income 44.3 0.4 1.9 — 46.6 Operating income (loss) 205.4 (1.0 ) (0.1 ) — 204.3 Equity in earnings of unconsolidated affiliates — 63.2 — — 63.2 Other income (expense) 8.5 — (1.3 ) (1.5 ) 5.7 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

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Equity Ownership (Details)	Jun. 30, 2019
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, 2019	Dec. 31, 2018
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries		$ 30.7	$ 2
Current Regulatory Assets		48.1	18.5
Non-Current Regulatory Assets		290	285.8
Current Regulatory Liabilities		36.3	36.6
Customer Refund Liability, Current		0.1	0.3
Non-Current Regulatory Liabilities		1,243	1,270.7
Reserve for Tax Refund [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	17.7	15.4
SPP Cost Tracker Rider Over Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	8	16.8
Oklahoma Demand Program Over Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	6.2	0
Transmission Cost Recovery Rider [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	1.1	2.7
Other (B)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	3.2	1.4
Non-Current Regulatory Liabilities		6.3	6.8
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		921.6	937.1
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		312.9	308.1
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		2.2	18.7
Cogeneration Credit Rider Over Credit [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	8.2	0
Oklahoma demand program rider under recovery (A)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	0	6.4
Production Tax Credit Rider [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	4.1	6.9
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		172.3	188.2
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		43.6	36.5
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		22.1	25.6
Dry Scrubber Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		21	4.5
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		11	11.4
Deferred Pension Expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		7.7	6.8
Other Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	5.1	3.2
Non-Current Regulatory Assets		$ 12.3	$ 12.8
[1]	Included in Other Current Liabilities in the Condensed Consolidated Balance Sheets.
[2]	Included in Other Current Assets in the Condensed Consolidated Balance Sheets.

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (21.1)	$ (22.3)	$ (28.9)	$ (23.2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.7	0.9
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax	(30)	(31)	(38.8)	(32.7)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1.7	1.7
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	4.5	2.5	4.6	2.5
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.1)	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	0	0
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	4.4	6.2	$ 5.3	$ 7
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.9)	$ (0.8)
Settlement Cost [Member]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	7.1
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	7.1
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Other Postretirement Benefits Plan [Member]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Pension Plan [Member]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefits Plan [Member]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 0

Summary of Significant Accoun_6

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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent		$ (1)	$ (0.7)	$ (7.8)	$ (0.9)
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)	(1.3)	(2.2)	(2.2)
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	[1]	(0.6)	0	(9.4)	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(1.9)	(1.3)	(11.6)	(2.2)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(0.4)	(0.3)	(2.8)	(0.5)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(1.5)	(1)	(8.8)	(1.7)
Other Postretirement Benefits 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]	0.1	0	0.1	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	[1]	0.5	0.5	1.1	1.1
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		0.6	0.5	1.2	1.1
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		0.1	0.2	0.2	0.3
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ 0.5	$ 0.3	$ 1	$ 0.8
[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 12 for additional information).

Accounting Pronouncements (Deta

Accounting Pronouncements (Details) - USD ($) $ in Millions	Jun. 30, 2019		Jan. 01, 2019
Accounting Pronouncements [Abstract]
Operating Lease, Right-of-Use Asset	$ 43.1	[1]	$ 34.5
Operating Lease, Liability	$ 47.8	[2]	$ 39.1
[1]	Included in Property, Plant and Equipment in the 2019 Condensed Consolidated Balance Sheet.
[2]	Included in Other Deferred Credits and Other Liabilities in the 2019 Condensed Consolidated Balance Sheet.

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 501.1	$ 547.7	$ 978.5	$ 1,025.6
Residential
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	182.3	217.3	373.5	413.5
Commercial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	115.4	135.1	210.8	235.9
Industrial
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	52.9	57	105.2	107.4
Oilfield
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	48.9	45.7	98.3	87.8
Public authorities and street light
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	44.4	51.1	84.5	92.8
System sales revenues
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	443.9	506.2	872.3	937.4
Provision for rate refund
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	(0.5)	(16.5)	(0.6)	(19.7)
Integrated market
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	10.3	13.1	17	21.8
Transmission
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	39.8	40.2	75.9	76
Other
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 7.6	$ 4.7	$ 13.9	$ 10.1

Leases (Details)

Leases (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019		Jun. 30, 2019		Dec. 31, 2018		Jan. 01, 2019
Operating Leased Assets [Line Items]
Lessee, Operating Lease, Contingent Liability	$ 6.8		$ 6.8		$ 16.2
Operating Leases, Rent Expense, Net					4.9
Operating lease cost	1.4		3
Cash Paid on Operating Leases			4.1
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability			10.7
Operating Lease, Right-of-Use Asset	43.1	[1]	43.1	[1]			$ 34.5
Operating Lease, Liability	$ 47.8	[2]	$ 47.8	[2]			$ 39.1
Operating Lease, Weighted Average Remaining Lease Term	13 years 3 months 18 days		13 years 3 months 18 days
Operating Lease, Weighted Average Discount Rate, Percent	3.90%		3.90%
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 1.7		$ 1.7		22.1	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Two	6.2		6.2		3.9	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Three	5.9		5.9		3.5	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Four	5.2		5.2		2.9	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due Year Five	5.1		5.1		2.9	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due after Year Five	37.8		37.8		37.6	[3],[4]
Lessee, Operating Lease, Liability, Payments, Due	61.9		61.9		$ 72.9	[3],[4]
Unrecorded Unconditional Purchase Obligation, Imputed Interest	$ 14.1		$ 14.1
[1]	Included in Property, Plant and Equipment in the 2019 Condensed Consolidated Balance Sheet.
[2]	Included in Other Deferred Credits and Other Liabilities in the 2019 Condensed Consolidated Balance Sheet.
[3]	Amounts included for comparability and accounted for in accordance with ASC 840, "Leases."
[4]	At the end of the railcar lease term, which was February 1, 2019, OG&E had the option to either purchase the railcars at a stipulated fair market value or renew the lease. OG&E renewed the lease effective February 1, 2019. If OG&E chose not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars was less than the stipulated fair market value, OG&E would have been responsible for the difference in those values up to a maximum of $16.2 million .

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018	May 01, 2013
Expected Settlement Charge			$ 12
Limited Partner Units Owned	111		111
Distribution Made to Limited Partner, Distributions Declared, Per Unit			$ 0.33050
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.50%	25.60%	25.50%	25.60%
Equity in earnings of unconsolidated affiliates	$ 35.8	$ 29.3	$ 66.5	$ 63.2
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	666.8		666.8		$ 680.3
Enogex LLC [Member]
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			25.50%
Enable Midstream Partners [Member]
Share Price	$ 13.71		$ 13.71

Investment in Unconsolidated _4

Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 3.8	$ 3.6	$ 7.6	$ 7.6
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	0.1	0.2	0.2	0.3
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	4	5.2	16.4	16.8
Natural Gas Transportation [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	9.3	8.8	24.1	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	(3.3)	$ 2.2	(4.3)	$ 2.5
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 1.2		$ 1.2		$ 1.7

Investment in Unconsolidated _5

Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 376	$ 449
Non-current assets	12,033	11,995
Current liabilities	1,270	1,615
Non-current liabilities	$ 3,580	$ 3,211

Investment in Unconsolidated _6

Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Schedule of Equity Method Investments [Line Items]
Total revenues	$ 735	$ 805	$ 1,530	$ 1,553
Cost of natural gas and NGLs	317	444	695	819
Operating income	167	126	332	265
Net income	$ 114.8	$ 86.4	$ 228	$ 191

Investment in Unconsolidated _7

Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Net income		$ 114.8	$ 86.4	$ 228	$ 191
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 666.8		$ 666.8		$ 680.3
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest		25.50%	25.60%	25.50%	25.60%
Proportionate Unconsolidated Affiliate Net Income		$ 29.3	$ 22.2	$ 58.2	$ 49
Amortization of basis difference	[1]	6.5	7.1	8.3	14.2
Equity in earnings of unconsolidated affiliates		35.8	29.3	66.5	63.2
Timing Differences Related to Equity Method Investee Net Income		0	0	0.1	0
Net Income Used to Calculate Equity in Earnings		$ 114.8	$ 86.4	$ 228.1	$ 191
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				25.50%
OGE Energy [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Amortization of basis difference	[2]			$ 13.5
[1]	Includes loss on dilution, net of proportional basis difference recognition .
[2]	Includes proportional basis difference recognition due to dilution.

Fair Value Measurements Carryin

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 3,048.6	$ 3,001.9
Long-Term Debt, Fair Value	3,428	3,178.2
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	9.6	9.6
Long-Term Debt, Fair Value	9.3	8.7
Fair Value, 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, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Stock-Based Compensation Activity
Income tax benefit	$ 0.7	$ 0.8	$ 1.5	$ 1.5
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	2.7	3.1	5.4	5.8
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	0.2	0	0.5	0
Share-based Payment Arrangement [Member]
Stock-Based Compensation Activity
Compensation expense	$ 2.9	3.1	$ 5.9	5.8
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Issued, Shares, Share-based Payment Arrangement, after Forfeiture	1,111		443,497
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 2.3	2.1	$ 4.5	4.1
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 0.4	$ 1	$ 0.9	$ 1.7

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Non-Current Regulatory Liabilities	$ 1,243	$ 1,270.7

Common Equity Automatic Dividen

Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details)	6 Months Ended
	Jun. 30, 2019shares
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, New Issues	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, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Equity [Abstract]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 100.2	$ 47.1	$ 110.7	$ 55	$ 147.3	$ 165.7
Basic average common shares outstanding	200.2		199.7		200.1	199.7
Contingently issuable shares (performance and restricted stock units)	0.4		0.8		0.4	0.6
Diluted average common shares outstanding	200.6		200.5		200.5	200.3
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share	$ 0.50		$ 0.55		$ 0.74	$ 0.83
Diluted earnings per average common share	$ 0.50		$ 0.55		$ 0.73	$ 0.83
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, 2019USD ($)
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.30%
Debt Instrument, Maturity Date	Mar. 15, 2030
Percent of Principal Amount Subject to Optional Tender	100.00%
Debt Instrument, Face Amount	$ 300
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	1.46%
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	1.43%
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	1.45%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
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	2.35%
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	2.48%

Short-Term Debt and Credit Fa_3

Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Short-term debt		$ 207.5	$ 0
Line of Credit Facility [Abstract]
Aggregate Commitment		900
Long-term Line of Credit	[1]	$ 207.8
Weighted Average Interest Rate		2.63%
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]	$ 207.5
Weighted Average Interest Rate	[2],[3]	2.63%
Maturity	[2]	Mar. 8, 2023
OG&E [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[4]	$ 450
Line of Credit Facility [Abstract]
Letters of Credit Outstanding, Amount	[1],[4]	$ 0.3
Weighted Average Interest Rate	[3],[4]	1.15%
Maturity	[4]	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, 2019 .
[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]	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 Postreti_3

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2019		Jun. 30, 2018		Jun. 30, 2019		Jun. 30, 2018
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement cost						$ 20.6
Net periodic benefit cost		$ (4.3)		$ (2.4)		(27.7)		$ (4.8)
Additional Pension Expense to Meet State Requirements						1.7		7.8
Pension Plan [Member]
Other Comprehensive Income (Loss), Defined Benefit Plan, Adjustment for Settlement or Curtailment Gain (Loss), Tax		0.1		0		2.3		0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		2.8	[1]	3.4	[1]	6.3	[2]	7.5	[2]
Interest cost		5.2	[1]	5.8	[1]	10.9	[2]	11.7	[2]
Expected return on plan assets		(8.9)	[1]	(11)	[1]	(17.6)	[2]	(22.3)	[2]
Amortization of net loss		4.8	[1]	4.4	[1]	8.6	[2]	8.3	[2]
Settlement cost		0.9	[1]	0	[1]	20.6	[2]	0	[2]
Total net periodic benefit cost		4.8	[1]	2.6	[1]	28.8	[2]	5.2	[2]
Less: Amount paid by unconsolidated affiliates		0.8	[1]	0.7	[1]	1.7	[2]	1.2	[2]
Net periodic benefit cost		(4)	[1]	(1.9)	[1]	(27.1)	[2]	(4)	[2]
Capitalized portion of net periodic pension benefit cost		0.8		0.9		1.8		1.9
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	[1]	0.2	[2]	0.2	[2]
Expected return on plan assets		0	[1]	0	[1]	0	[2]	0	[2]
Amortization of net loss		0.1	[1]	0.3	[1]	0.2	[2]	0.4	[2]
Settlement cost		0	[1]	0	[1]	0	[2]	0	[2]
Total net periodic benefit cost		0.3	[1]	0.5	[1]	0.6	[2]	0.8	[2]
Less: Amount paid by unconsolidated affiliates		0	[1]	0	[1]	0	[2]	0	[2]
Net periodic benefit cost		(0.3)	[1]	(0.5)	[1]	(0.6)	[2]	(0.8)	[2]
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0	[3]	0.1	[3]	0.1	[4]	0.2	[4]
Interest cost		1.4	[3]	1.3	[3]	2.8	[4]	2.6	[4]
Expected return on plan assets		(0.4)	[3]	(0.5)	[3]	(0.9)	[4]	(1)	[4]
Amortization of net loss		0.4	[3]	0.9	[3]	1	[4]	1.9	[4]
Amortization of unrecognized prior service cost (A)	[5]	(2.1)	[3]	(2.1)	[3]	(4.2)	[4]	(4.2)	[4]
Total net periodic benefit cost		(0.7)	[3]	(0.3)	[3]	(1.2)	[4]	(0.5)	[4]
Less: Amount paid by unconsolidated affiliates		(0.1)	[3]	(0.1)	[3]	(0.3)	[4]	(0.2)	[4]
Net periodic benefit cost		0.6	[3]	0.2	[3]	0.9	[4]	0.3	[4]
Capitalized portion of net periodic pension benefit cost		0		0.1		0.1		0.1
OKLAHOMA | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement cost						(11.7)
Additional Pension Expense to Meet State Requirements		0.7		3.8
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements		$ 0.5		$ 2.2		0.8		$ 4.3
ARKANSAS | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement cost						$ (1.1)
[1]	In addition to the $4.3 million and $2.4 million of net periodic benefit cost recognized during the three months ended June 30, 2019 and 2018 , respectively , the Company recognized a decrease of pension expense of $0.7 million and an increase of $3.8 million during the three months ended June 30, 2019 and 2018 , 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)
[2]	In addition to the $27.7 million and $4.8 million of net periodic benefit cost recognized during the six months ended June 30, 2019 and 2018 , respectively , the Company recognized the following: • a decrease of pension expense of $1.7 million and an increase of $7.8 million during the six months ended June 30, 2019 and 2018 , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1) ; • a deferral of pension expense during the six months ended June 30, 2019 of $11.7 million related to the pension settlement charge of $20.6 million in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the six months ended June 30, 2019 of $1.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $20.6 million
[3]	In addition to the $0.6 million and $0.2 million of net periodic benefit income recognized during the three months ended June 30, 2019 and 2018 , respectively, the Company recognized an increase in postretirement medical expense during the three months ended June 30, 2019 and 2018 of $0.5 million and $2.2 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 $0.9 million and $0.3 million of net periodic benefit income recognized during the six months ended June 30, 2019 and 2018 , respectively, the Company recognized an increase in postretirement medical expense during the six months ended June 30, 2019 and 2018 of $0.8 million and $4.3 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1).
[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, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Segment Reporting Information [Line Items]
Operating revenues	$ 513.7		$ 567		$ 1,003.7	$ 1,059.7
Cost of sales	178.7		208.7		391.3	419.2
Other operation and maintenance	119.8		117.2		238.8	229.9
Depreciation and amortization	84.3		80.9		166.7	159.7
Taxes other than income	20.9		22.5		47.2	46.6
OPERATING INCOME	110		137.7		159.7	204.3
Equity in earnings of unconsolidated affiliates	35.8		29.3		66.5	63.2
Other income (expense)	1.5		2.5		(3)	5.7
Interest expense	35.9		40.9		70.5	79.5
Income tax expense (benefit)	11.2		17.9		5.4	28
Net income (loss)	100.2	$ 47.1	110.7	$ 55	147.3	165.7
Investment in unconsolidated affiliates	1,171.3		1,153.6		1,171.3	1,153.6	$ 1,177.5
Total assets	10,886.2		10,543.6		10,886.2	10,543.6	$ 10,748.6
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	513.7		567		1,003.7	1,059.7
Cost of sales	178.7		208.7		391.3	419.2
Other operation and maintenance	120		117.5		240.3	231.1
Depreciation and amortization	84.3		80.9		166.7	159.7
Taxes other than income	20.1		21.6		44.5	44.3
OPERATING INCOME	110.6		138.3		160.9	205.4
Equity in earnings of unconsolidated affiliates	0		0		0	0
Other income (expense)	1.5		4		4.1	8.5
Interest expense	33.3		39.2		65.7	76.5
Income tax expense (benefit)	4.3		11.1		5.2	14.1
Net income (loss)	74.5		92		94.1	123.3
Investment in unconsolidated affiliates	0		0		0	0
Total assets	9,733.8		9,447.8		9,733.8	9,447.8
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		0.3		0.7	0.6
Depreciation and amortization	0		0		0	0
Taxes other than income	0.1		0.2		0.3	0.4
OPERATING INCOME	(0.4)		(0.5)		(1)	(1)
Equity in earnings of unconsolidated affiliates	35.8		29.3		66.5	63.2
Other income (expense)	(0.4)		0		(7.8)	0
Interest expense	0		0		0	0
Income tax expense (benefit)	8.1		6.7		9.5	16.5
Net income (loss)	26.9		22.1		48.2	45.7
Investment in unconsolidated affiliates	1,157.2		1,144.6		1,157.2	1,144.6
Total assets	1,160		1,147.9		1,160	1,147.9
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	(0.5)		(0.6)		(2.2)	(1.8)
Depreciation and amortization	0		0		0	0
Taxes other than income	0.7		0.7		2.4	1.9
OPERATING INCOME	(0.2)		(0.1)		(0.2)	(0.1)
Equity in earnings of unconsolidated affiliates	0		0		0	0
Other income (expense)	1		(0.6)		1.7	(1.3)
Interest expense	3.2		2.6		5.8	4.5
Income tax expense (benefit)	(1.2)		0.1		(9.3)	(2.6)
Net income (loss)	(1.2)		(3.4)		5	(3.3)
Investment in unconsolidated affiliates	14.1		9		14.1	9
Total assets	104.5		95.6		104.5	95.6
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)	(0.6)		(0.9)		(1)	(1.5)
Interest expense	(0.6)		(0.9)		(1)	(1.5)
Income tax expense (benefit)	0		0		0	0
Net income (loss)	0		0		0	0
Investment in unconsolidated affiliates	0		0		0	0
Total assets	$ (112.1)		$ (147.7)		$ (112.1)	$ (147.7)

Rate Matters and Regulation Rat

Rate Matters and Regulation Rate Matters and Regulation (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)
Public Utilities, Amount Requested for Acquisition	$ 53.5
Estimated Refund to SPP	13
Dry Scrubber Project [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	512.4
Muskogee Natural Gas Conversion [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	57
OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount	77.6
ARKANSAS
Public Utilities, Approved Rate Increase (Decrease), Amount	$ (3.3)
FERC [Member]
Public Utilities, Approved Return on Equity, Percentage	10.60%
Recommended Common Equity Percentage	7.85%
Impact to Company [Member]
Estimated Refund to SPP	$ 5
Customer Impact [Member]
Estimated Refund to SPP	$ 8