OGE Energy (OGE) 10-Q 2 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information Document	9 Months Ended
	Sep. 30, 2017shares
Document Information [Line Items]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	1,021,635
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,705,254

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
OPERATING REVENUES	$ 716.8	$ 743.9	$ 1,759.2	$ 1,728.4
COST OF SALES	255.7	269.8	696.5	645.4
OPERATING EXPENSES
Other operation and maintenance	117.7	113.1	356.5	354.6
Depreciation and amortization	76.9	82.2	207.2	240.8
Taxes other than income	23.2	21.5	68.4	66.5
Total operating expenses	217.8	216.8	632.1	661.9
OPERATING INCOME	243.3	257.3	430.6	421.1
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	33.6	34.5	98.6	79.5
Allowance for equity funds used during construction	11.8	3.9	27.2	9.2
Other income	15	5.7	34.1	18.9
Other expense	(2)	(3.3)	(9.3)	(10.8)
Net other income	58.4	40.8	150.6	96.8
INTEREST EXPENSE
Interest on long-term debt	38.7	35.8	113.8	107.3
Allowance for borrowed funds used during construction	(5.2)	(2)	(12.6)	(4.7)
Interest on short-term debt and other interest charges	2.4	1.6	6.8	5.1
Interest expense	35.9	35.4	108	107.7
INCOME BEFORE TAXES	265.8	262.7	473.2	410.2
INCOME TAX EXPENSE	82.4	79.1	149	129.9
NET INCOME	$ 183.4	$ 183.6	$ 324.2	$ 280.3
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7	199.7	199.7	199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.1	199.9	200	199.8
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.92	$ 0.92	$ 1.62	$ 1.40
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.92	0.92	1.62	1.40
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.33250	$ 0.30250	$ 0.93750	$ 0.85250

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net income	$ 183.4	$ 183.6	$ 324.2	$ 280.3
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.5, $0.4, $1.3 and $1.2, respectively	0.6	0.8	2	2.3
Settlement cost, net of tax of $0.0, $0.0, $0.0 and $3.2, respectively	0	0	0	5
Postretirement Benefit Plans:
Prior service cost arising during the period, net of tax of $4.1, $0.0, $4.1 and $0.0, respectively	6.7	0	6.7	0
Amortization of prior service cost, net of tax of ($0.2), ($0.2), ($0.2) and ($0.7), respectively	(0.2)	(0.4)	(0.2)	(1.2)
Settlement cost, net of tax of $0.2, $0.0, $0.2 and $0.0, respectively	0.5	0	0.5	0
Other comprehensive income, net of tax	7.6	0.4	9	6.1
Comprehensive income	$ 191	$ 184	$ 333.2	$ 286.4

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.5	$ 0.4	$ 1.3	$ 1.2
Settlement cost	0	0	0	3.2
Postretirement Benefit Plans:
Amortization of prior service cost	(0.2)	(0.2)	(0.2)	(0.7)
Other Comprehensive Income Reclassification Of Defined Benefit Postretirement Plans Net Gain Loss Recognized In Net Periodic Benefit Cost Tax	$ 4.1	$ 0	$ 4.1	$ 0

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 324.2	$ 280.3
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	207.2	240.8
Deferred income taxes and investment tax credits, net	152.1	134.2
Equity in earnings of unconsolidated affiliates	(98.6)	(79.5)
Distributions from unconsolidated affiliates	98.6	79.9
Allowance for equity funds used during construction	(27.2)	(9.2)
Stock-based compensation	4.7	3.2
Regulatory assets	10.9	(10.5)
Regulatory liabilities	(0.6)	(9.8)
Other assets	(2)	18
Other liabilities	(70.8)	(19.8)
Change in certain current assets and liabilities
Accounts receivable, net	(87.2)	(51.9)
Accrued unbilled revenues	(10.1)	(17.5)
Fuel, materials and supplies inventories	4.1	30.9
Fuel clause under recoveries	15.8	(0.5)
Other current assets	26.8	(13.1)
Accounts payable	(29.1)	(90.6)
Fuel clause over recoveries	0	(59.9)
Other current liabilities	(55.1)	1.9
Net cash provided from operating activities	463.7	426.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(662.8)	(466.7)
Investments in and Advances to Affiliates, at Fair Value, Period Increase (Decrease)	(5.2)	0
Return of capital - equity method investments	7.3	25.9
Proceeds from sale of assets	0.4	0.3
Net cash used in investing activities	(660.3)	(440.5)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(181.2)	(164.7)
Proceeds from long-term debt	592.3	0
Payment of long-term debt	(125.1)	(110.1)
Increase (decrease) in short-term debt	(89.7)	213.2
Net cash provided from (used in) financing activities	196.3	(61.6)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(0.3)	(75.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	0.3	75.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 0		$ 0.3
Accounts receivable, less reserve of $1.5 and $1.5, respectively	261.5		173
Accounts receivable - unconsolidated affiliates	1.2		2.5
Accrued unbilled revenues	69.8		59.7
Income taxes receivable	17		19.4
Fuel inventories	77.2		79.8
Materials and supplies, at average cost	80.2		81.7
Fuel clause under recoveries	35.5		51.3
Other	57.4		81.8
Total current assets	599.8		549.5
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,158.1		1,158.6
Other	76.4		73.6
Total other property and investments	1,234.5		1,232.2
PROPERTY, PLANT AND EQUIPMENT
In service	10,890.3		10,690
Construction work in progress	893.9		495.1
Total property, plant and equipment	11,784.2		11,185.1
Less accumulated depreciation	3,584.3		3,488.9
Net property, plant and equipment	8,199.9		7,696.2
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	373.4		404.8
Other	56.1		56.9
Total deferred charges and other assets	429.5		461.7
TOTAL ASSETS	10,463.7		9,939.6
CURRENT LIABILITIES
Short-term debt	146.5		236.2
Accounts payable	145.5		205.4
Dividends payable	66.4		60.4
Customer deposits	79.5		77.7
Accrued taxes	60.2		41.3
Accrued interest	39		40.4
Accrued compensation	30.3		45.1
Long-term debt due within one year	349.7		224.7
Other	36.4		96
Total current liabilities	953.5		1,027.2
LONG-TERM DEBT	2,749.5		2,405.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	185.8		274.8
Deferred income taxes	2,465.9		2,334.5
Regulatory liabilities	331.7		299.7
Other	160.5		153.8
Total deferred credits and other liabilities	3,143.9		3,062.8
Total liabilities	6,846.9		6,495.8
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,110.5		1,105.8
Retained earnings	2,526.6		2,367.3
Accumulated other comprehensive loss, net of tax	(20.3)		(29.3)
Total stockholders' equity	3,616.8		3,443.8
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 10,463.7		$ 9,939.6

CONDENSED CONSOLIDATED BALANCE7

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 1.5

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Unaudited) - USD ($) $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2015	$ 3,326	$ 2	$ 1,099.3	$ 2,259.8	$ (35.1)
Changes in Stockholders' Equity
Net income	280.3	0	0	280.3	0
Other comprehensive income, net of tax	6.1	0	0	0	6.1
Dividends declared on common stock	(170.3)	0	0	(170.3)	0
Stock-based compensation	3.1	0	3.1	0	0
Balance at Sep. 30, 2016	3,445.2	2	1,102.4	2,369.8	(29)
Balance at Dec. 31, 2016	3,443.8	2	1,103.8	2,367.3	(29.3)
Changes in Stockholders' Equity
Net income	324.2	0	0	324.2	0
Other comprehensive income, net of tax	9	0	0	0	9
Dividends declared on common stock	(187.2)	0	0	(187.2)	0
Stock-based compensation	4.7	0	4.7	0	0
Balance at Sep. 30, 2017	3,616.8	2	1,108.5	2,526.6	(20.3)
Changes in Stockholders' Equity
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 22.3	$ 0	$ 0	$ 22.3	$ 0

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Summary of Significant Accounting Policies Organization The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable, and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting. Basis of Presentation The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading. In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at September 30, 2017 and December 31, 2016 , the results of its operations for the three and nine months ended September 30, 2017 and 2016 and its cash flows for the nine months ended September 30, 2017 and 2016 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after September 30, 2017 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 nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 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 2016 Form 10-K.
Schedule of Regulatory Assets and Liabilities	Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. The following table is a summary of OG&E's regulatory assets and liabilities at: September 30, December 31, (In millions) 2017 2016 Regulatory Assets Current Oklahoma demand program rider under recovery (A) $ 38.3 $ 51.0 Fuel clause under recoveries 35.5 51.3 SPP cost tracker under recovery (A) 7.8 10.0 Other (A) 2.6 9.5 Total current regulatory assets $ 84.2 $ 121.8 Non-current Benefit obligations regulatory asset $ 189.0 $ 232.6 Income taxes recoverable from customers, net 76.3 62.3 Deferred storm expenses 43.3 35.7 Smart Grid 34.7 43.2 Unamortized loss on reacquired debt 12.5 13.4 Other 17.6 17.6 Total non-current regulatory assets $ 373.4 $ 404.8 Regulatory Liabilities Current Other (B) $ 3.3 $ 12.3 Total current regulatory liabilities $ 3.3 $ 12.3 Non-current Accrued removal obligations, net $ 282.0 $ 262.8 Pension tracker 40.4 35.5 Other 9.3 1.4 Total non-current regulatory liabilities $ 331.7 $ 299.7 (A) Included in Other Current Assets on the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. The following table summarizes changes to the Company's asset retirement obligations during the nine months ended September 30, 2017 and 2016 . Nine Months Ended September 30, (In millions) 2017 2016 Balance at January 1 $ 69.6 $ 63.3 Accretion expense 2.3 2.1 Liabilities settled — (0.2 ) Revisions in estimated cash flows 2.4 — Balance at September 30 $ 74.3 $ 65.2
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 nine months ended September 30, 2017 and 2016 . All amounts below are presented net of tax. Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service cost Total Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) Other comprehensive income before reclassifications — — — 6.7 6.7 Amounts reclassified from accumulated other comprehensive income (loss) 2.0 — — (0.2 ) 1.8 Settlement cost — — 0.5 — 0.5 Net current period other comprehensive income 2.0 — 0.5 6.5 9.0 Balance at September 30, 2017 $ (30.1 ) $ 0.1 $ 3.2 $ 6.5 $ (20.3 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service cost Total Balance at December 31, 2015 $ (39.2 ) $ 0.1 $ 2.5 $ 1.5 $ (35.1 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.3 — — (1.2 ) 1.1 Settlement cost 5.0 — — — 5.0 Net current period other comprehensive income (loss) 7.3 — — (1.2 ) 6.1 Balance at September 30, 2016 $ (31.9 ) $ 0.1 $ 2.5 $ 0.3 $ (29.0 ) The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and nine months ended September 30, 2017 and 2016 . 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 Comprehensive Income Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 2016 2017 2016 Amortization of Pension Plan and Restoration of Retirement Income Plan items Actuarial losses (A) $ (1.1 ) $ (1.2 ) $ (3.3 ) $ (3.5 ) Other Operation and Maintenance Expense Settlement (A) — — — (8.2 ) Other Operation and Maintenance Expense (1.1 ) (1.2 ) (3.3 ) (11.7 ) Income Before Taxes (0.5 ) (0.4 ) (1.3 ) (4.4 ) Income Tax Expense $ (0.6 ) $ (0.8 ) $ (2.0 ) $ (7.3 ) Net Income Amortization of postretirement benefit plan items Prior service credit (A) $ 0.4 $ 0.6 $ 0.4 $ 1.9 Other Operation and Maintenance Expense Settlement (A) (0.7 ) — (0.7 ) — Other Operation and Maintenance Expense (0.3 ) 0.6 (0.3 ) 1.9 Income Before Taxes — 0.2 — 0.7 Income Tax Expense $ (0.3 ) $ 0.4 $ (0.3 ) $ 1.2 Net Income Total reclassifications for the period, net of tax $ (0.9 ) $ (0.4 ) $ (2.3 ) $ (6.1 ) Net Income (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Accounting Pronouncements

Accounting Pronouncements	9 Months Ended
	Sep. 30, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting Pronouncements Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The new revenue standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 2017. The Company has assessed the effect of this new guidance on its tariff-based sales, bundled arrangements and alternative revenue program and is not aware of any issues that would have a material impact on the timing of revenue recognition. The new standard will not have a material impact on the Company's results of operations and financial position but will change the income statement presentation of revenues and require new disclosures. The Company does not intend to early adopt the new guidance and will implement in the first quarter of 2018 utilizing the modified retrospective transition method. Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between current lease accounting and Topic 842 is the recognition of right-to-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance . Lessees, such as the Company, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition method and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has started evaluating its current lease contracts. The Company has not determined the amount of impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities. Employee Share-Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which amends Accounting Standards Codification Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share-based payments are accounted for and presented in the financial statements. The new guidance, among other requirements, requires all of the tax effects related to share-based payments at settlement (or expiration) to be recorded through the income statement. Previously, tax benefits in excess of compensation cost, or windfalls, were recorded in equity, and tax deficiencies, or shortfalls, were recorded in equity to the extent of previous windfalls and then to the income statement. Under the new guidance, the windfall tax benefit is recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax-related cash flows resulting from share-based payments are to be reported as operating activities on the statement of cash flows, which is a change from the previous requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The Company adopted this standard in the first quarter of 2017 and recorded a cumulative effect of $22.3 million as a deferred tax asset with an offset in retained earnings. Going forward, tax benefits in excess of compensation costs previously recorded in equity will be recorded within the income statement, and all tax-related cash flows resulting from share-based payments will be recorded as an operating activity within the statement of cash flows. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit expense between those that are attributed to compensation for service and those that are not. The service cost component of benefit expense will continue to be presented within operating income, but entities will now be required to present the other components of benefit expense as non-operating within the income statement. Additionally, the new guidance only permits the capitalization of the service cost component of net benefit expense. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs. The new guidance is effective for annual periods beginning after December 2017, including interim periods within those annual periods. Early adoption is permitted, subject to certain conditions. The Company believes that the impact of the change in capitalization of only the service cost component of net periodic benefit costs will be immaterial from current practice. The Company does not intend to early adopt the new guidance and will implement the change in the first quarter of 2018.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates	9 Months Ended
	Sep. 30, 2017
Related Party Transactions [Abstract]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	Investment in Unconsolidated Affiliate The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; 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 September 30, 2017 as presented in Note 11. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable, which do not exceed cumulative equity in earnings subsequent to the date of investment, to be a return on investment and are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment and are classified as investing activities in the Condensed Consolidated Statements of Cash Flows. Investment in Unconsolidated Affiliate and Related Party Transactions On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013. Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable . The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. Enable completed an initial public offering resulting in Enable becoming a publicly traded Master Limited Partnership in April 2014. At September 30, 2017 , the Company owned 111.0 million common units, or 25.7 percent of Enable's outstanding common units. Prior to August 30, 2017, 68.2 million of the 111.0 million common units were subordinated. The subordination period began on the closing date of Enable's initial public offering and extended until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. On August 30, 2017, the first day following the payment of the cash distribution for common and subordinated units for the second quarter of 2017, the subordination period expired for the Company's 68.2 million subordinated units. On October 31, 2017, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election. Distributions received from Enable were $35.3 million during both the three months ended September 30, 2017 and 2016 and $105.9 million during both the nine months ended September 30, 2017 and 2016 . On January 16, 2017, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided a second notice to the Company of CenterPoint's solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. On February 15, 2017, under the terms of right of first offer, the Company submitted to CenterPoint another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in the general partner of Enable and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint within the required timeframe. On July 15, 2017, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided a third notice to the Company of CenterPoint's solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. On August 14, 2017, under the terms of right of first offer, the Company submitted to CenterPoint another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in the general partner of Enable and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint within the required timeframe. In accordance with the provisions of the partnership agreement, CenterPoint has until January 11, 2018 to solicit additional offers in excess of the Company's offer. If the Company's August 14, 2017 proposal had been accepted by CenterPoint, and if the transaction contemplated by the proposal was in fact consummated, the Company anticipated that the third party would, as a result of such transaction, become the owner of all or substantially all of the securities subject to the right of first offer. The Company's ownership interest in Enable would not have materially changed as a result of such transaction; therefore, the Company would not have been required to consolidate the financial results of Enable with the financial results of the Company. The Company cannot predict what future actions CenterPoint will take, if any, associated with their ownership interest in Enable. Related Party Transactions Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below. In connection with the formation of Enable, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement and other agreements whereby the Company agreed to provide certain support services to Enable, such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2017. Under these agreements, the Company charged operating costs to Enable of $0.7 million and $1.0 million for the three months ended September 30, 2017 and 2016 , respectively, and $2.2 million and $3.6 million for the nine months ended September 30, 2017 and 2016 , respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as such. Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. The Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, the Company, CenterPoint and Enable agreed to continue the secondment to Enable of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $6.2 million and $6.6 million during the three months ended September 30, 2017 and 2016 , respectively, and $23.5 million and $21.8 million for the nine months ended September 30, 2017 and 2016 , respectively, under the Transitional Seconding Agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $14.5 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 day notice. The Company had accounts receivable from Enable for amounts billed for transitional services, including the cost of seconded employees, of $2.2 million as of September 30, 2017 and $2.7 million as of December 31, 2016 . Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. The following table summarizes related party transactions between OG&E and Enable during the three and nine months ended September 30, 2017 and 2016 . Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 2016 2017 2016 Operating revenues: Electricity to power electric compression assets $ 4.5 $ 3.7 $ 10.0 $ 9.0 Cost of sales: Natural gas transportation services $ 8.8 $ 8.8 $ 26.3 $ 26.3 Natural gas purchases (sales) 0.4 4.4 (0.4 ) 11.3 Summarized Financial Information of Enable Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2017 and December 31, 2016 and for the three and nine months ended September 30, 2017 and 2016 . September 30, December 31, Balance Sheet 2017 2016 (In millions) Current assets $ 446 $ 396 Non-current assets 10,816 10,816 Current liabilities 831 362 Non-current liabilities 2,740 3,056 Three Months Ended Nine Months Ended September 30, September 30, Income Statement 2017 2016 2017 2016 (In millions) Operating revenues $ 705 $ 620 $ 1,997 $ 1,658 Cost of natural gas and NGLs 349 268 936 717 Operating income 137 139 399 299 Net income 104 110 301 231 The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value. Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to equity of $2.2 billion . Due to the contribution of Enogex LLC to Enable meeting the requirements of being in substance real estate and thus recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable. The Company recorded equity in earnings of unconsolidated affiliates of $33.6 million and $34.5 million for the three months ended September 30, 2017 and 2016 , respectively, and $98.6 million and $79.5 million for the nine months ended September 30, 2017 and 2016 , respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex LLC and its underlying equity in the net assets of Enable. The basis difference is being amortized over approximately 30 years, which is the average life of the assets to which the basis difference is attributed, beginning in May 2013. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments , as described below. The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three and nine months ended September 30, 2017 and 2016 . Three Months Ended Nine Months Ended September 30, September 30, Reconciliation of Equity in Earnings of Unconsolidated Affiliates 2017 2016 2017 2016 (In millions) Enable net income $ 104.0 $ 110.1 $ 301.0 $ 230.8 Distributions senior to limited partners — (9.1 ) — (9.1 ) Differences due to timing of OGE Energy and Enable accounting close — 3.0 — (7.2 ) Enable net income used to calculate OGE Energy's equity in earnings $ 104.0 $ 104.0 $ 301.0 $ 214.5 OGE Energy's percent ownership at period end 25.7 % 26.3 % 25.7 % 26.3 % OGE Energy's portion of Enable net income $ 26.5 $ 27.3 $ 77.2 $ 55.9 Impairments recognized by Enable associated with OGE Energy's basis differences — — — 1.8 OGE Energy's share of Enable net income $ 26.5 $ 27.3 $ 77.2 $ 57.7 Amortization of basis difference 2.8 2.9 8.5 8.8 Elimination of Enable fair value step up 4.3 4.3 12.9 13.0 Equity in earnings of unconsolidated affiliates $ 33.6 $ 34.5 $ 98.6 $ 79.5 The difference between the OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $721.4 million as of September 30, 2017 . The following table reconciles the basis difference in Enable from December 31, 2016 to September 30, 2017 . (In millions) Basis difference as of December 31, 2016 $ 743.7 Change in Enable basis difference (0.9 ) Amortization of basis difference (8.5 ) Elimination of Enable fair value step up (12.9 ) Basis difference as of September 30, 2017 $ 721.4

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1), and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). The Company had no financial instruments measured at fair value on a recurring basis at September 30, 2017 and December 31, 2016 . The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2017 and December 31, 2016 . September 30, December 31, 2017 2016 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year) Senior Notes $ 2,854.1 $ 3,179.4 $ 2,385.5 $ 2,657.2 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.7 9.6 9.9 9.5 OGE Energy Senior Notes 100.0 100.0 99.7 99.9

Stock-Based Compensation

Stock-Based Compensation	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	Stock-Based Compensation The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and nine months ended September 30, 2017 and 2016 related to the Company's performance units and restricted stock . Three Months Ended September 30, Nine Months Ended September 30, (In millions) 2017 2016 2017 2016 Performance units Total shareholder return $ 1.6 $ 1.2 $ 4.9 $ 3.4 Earnings per share (1.4 ) (1.3 ) (0.2 ) (0.3 ) Total performance units 0.2 (0.1 ) 4.7 3.1 Restricted stock 0.1 — 0.1 0.1 Total compensation expense $ 0.3 $ (0.1 ) $ 4.8 $ 3.2 Income tax benefit $ 0.1 $ — $ 1.9 $ 1.3 During the three and nine months ended September 30, 2017 , the Company issued an immaterial number of shares to satisfy restricted stock grants.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2014 or state and local tax examinations by tax authorities for years prior to 2013 . Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

Common Equity

Common Equity	9 Months Ended
	Sep. 30, 2017
Common Equity [Text Block]	Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months ended September 30, 2017 . Earnings Per Share Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted-average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted-average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units. Basic and diluted earnings per share for the Company were calculated as follows: Three Months Ended September 30, Nine Months Ended September 30, (In millions except per share data) 2017 2016 2017 2016 Net income $ 183.4 $ 183.6 $ 324.2 $ 280.3 Average common shares outstanding: Basic average common shares outstanding 199.7 199.7 199.7 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.4 0.2 0.3 0.1 Diluted average common shares outstanding 200.1 199.9 200.0 199.8 Basic earnings per average common share $ 0.92 $ 0.92 $ 1.62 $ 1.40 Diluted earnings per average common share $ 0.92 $ 0.92 $ 1.62 $ 1.40 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2017
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	Long-Term Debt At September 30, 2017 , the Company was in compliance with all of its debt agreements. OG&E Industrial Authority Bonds OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows: SERIES DATE DUE AMOUNT (In millions) 0.65% - 1.03% Garfield Industrial Authority, January 1, 2025 $ 47.0 0.65% - 0.97% Muskogee Industrial Authority, January 1, 2025 32.4 0.66% - 0.98% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4 All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third-party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-term Debt in the Company's Condensed Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations. Issuance of New Long-Term Debt In March 2017, OG&E issued $300.0 million of 4.15 percent senior notes due April 1, 2047 . The proceeds from the issuance were used to repay short-term debt and were added to OG&E's general funds to be used for general corporate purposes, including to repay borrowings under the revolving credit facility, to fund the payment of OG&E's $125.0 million of 6.5 percent senior notes that matured on July 15, 2017 and to fund ongoing capital expenditures and working capital. In August 2017, OG&E issued $300.0 million of 3.85 percent senior notes due August 15, 2047 . The proceeds from the issuance were used for general corporate purposes, including to repay short-term debt, to repay borrowings under the revolving credit facility, to fund ongoing capital expenditures and for working capital.

Short-Term Debt and Credit Faci

Short-Term Debt and Credit Facilities	9 Months Ended
	Sep. 30, 2017
Short-term Debt [Abstract]
Short-Term Debt and Credit Facilities	Short-Term Debt and Credit Facilities On March 8, 2017, the Company and OG&E each entered into new $450.0 million unsecured five-year revolving credit facilities to replace existing facilities. Each of these new facilities is scheduled to terminate on March 8, 2022 . However, the Company and OG&E have the right to request an extension of the revolving credit facility termination date under their respective facility for an additional one-year period, which can be exercised up to two times. All such extension requests are subject to majority lender group approval (and only the commitments of those lenders that consent to such extension (or that agree to replace any non-consenting lender) will be extended for such additional period). Borrowings under the new facilities bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.69 percent to 1.275 percent , or an alternate base rate, plus a margin of 0.0 percent to 0.275 percent . The new facilities have a facility fee that ranges from 0.06 percent to 0.225 percent . Interest rate margins and facility fees are based on the Company's and OG&E's then-current senior unsecured credit ratings, as applicable. Each of the facilities provides for issuance of letters of credit, provided that (i) the aggregate outstanding credit exposure shall not exceed the amount of the revolving credit facility and (ii) the aggregate outstanding stated amount of letters of credit issued under such facility shall not exceed a specified maximum sublimit ( $100 million for each of the Company and OG&E). Advances under the facilities may be used to refinance existing indebtedness and for working capital and general corporate purposes of the respective borrower and its subsidiaries, including commercial paper liquidity support, letters of credit, acquisitions and distributions. Each of the facilities is unsecured and, under certain circumstances, may be increased (by up to $150 million in each case for the Company and OG&E) to a maximum revolving commitment limit of $600 million . Advances of revolving loans and letters of credit under the facilities are subject to certain conditions precedent, including the accuracy of certain representations and warranties and the absence of any default or unmatured default. The Company and OG&E's facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent , as defined in each such facility. The Company and OG&E's facilities each also contain covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods. As of September 30, 2017 , the Company had $146.5 million of short-term debt as compared to $236.2 million at December 31, 2016 . The following table provides information regarding the Company's revolving credit agreements at September 30, 2017 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ 146.5 1.43 % (D) March 8, 2022 OG&E (C) 450.0 0.3 0.95 % (D) March 8, 2022 Total $ 900.0 $ 146.8 1.43 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2017 . (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, 2017 and ending December 31, 2018.

Retirement Plans and Postretire

Retirement Plans and Postretirement Benefit Plans	9 Months Ended
	Sep. 30, 2017
Defined Benefit Plan [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Retirement Plans and Postretirement Benefit Plans The details of net periodic benefit cost, before consideration of capitalized amounts, of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows: Net Periodic Benefit Cost Pension Plan Restoration of Retirement Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended September 30, September 30, September 30, September 30, (In millions) 2017 2016 2017 2016 2017 2016 2017 2016 Service cost $ 3.9 $ 4.0 $ 11.6 $ 11.9 $ — $ — $ 0.2 $ 0.2 Interest cost 6.5 6.4 19.6 19.1 0.1 0.1 0.2 0.3 Expected return on plan assets (10.7 ) (10.4 ) (32.0 ) (31.1 ) — — — — Amortization of net loss 4.4 4.1 13.1 12.3 0.1 0.2 0.3 0.5 Amortization of unrecognized prior service cost (A) — (0.1 ) — (0.1 ) 0.1 0.1 0.1 0.1 Settlement — — — — — — — 8.7 Total net periodic benefit cost 4.1 4.0 12.3 12.1 0.3 0.4 0.8 9.8 Less: Amount paid by unconsolidated affiliates 1.2 1.3 2.9 3.8 — 0.1 — 0.3 Net periodic benefit cost (net of unconsolidated affiliates) $ 2.9 $ 2.7 $ 9.4 $ 8.3 $ 0.3 $ 0.3 $ 0.8 $ 9.5 (A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment. (B) In addition to the $3.2 million and $3.0 million of net periodic benefit cost recognized during the three months ended September 30, 2017 and 2016 , respectively , OG&E recognized an increase in pension expense during the three months ended September 30, 2017 and 2016 of $2.7 million and $2.4 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1) . (C) In addition to the $10.2 million and $17.8 million of net periodic benefit cost recognized during the nine months ended September 30, 2017 and 2016 , respectively , OG&E recognized the following: • an increase in pension expense during the nine months ended September 30, 2017 and 2016 of $8.5 million and $7.4 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1) ; • a deferral of pension expense during the nine months ended September 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013 ; • a deferral of pension expense during the nine months ended September 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million , in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the nine months ended September 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million . Postretirement Benefit Plans Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 (B) 2016 (B) 2017 (C) 2016 (C) Service cost $ 0.1 $ 0.2 $ 0.5 $ 0.6 Interest cost 1.6 2.4 5.9 7.1 Expected return on plan assets (0.6 ) (0.6 ) (1.7 ) (1.7 ) Amortization of net loss 0.5 0.6 1.3 1.9 Amortization of unrecognized prior service cost (A) (1.4 ) (2.1 ) (1.4 ) (6.5 ) Settlement 0.6 — 0.6 — Total net periodic benefit cost 0.8 0.5 5.2 1.4 Less: Amount paid by unconsolidated affiliates (0.1 ) — 0.5 0.1 Net periodic benefit cost (net of unconsolidated affiliates) $ 0.9 $ 0.5 $ 4.7 $ 1.3 (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 $0.9 million and $0.5 million of net periodic benefit cost recognized during the three months ended September 30, 2017 and 2016 , respectively, OG&E recognized an increase in postretirement medical expense of $1.9 million in both the three months ended September 30, 2017 and 2016 to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1). (C) In addition to the $4.7 million and $1.3 million of net periodic benefit cost recognized during the nine months ended September 30, 2017 and 2016 , respectively, OG&E recognized an increase in postretirement medical expense in the nine months ended September 30, 2017 and 2016 of $3.9 million and $5.9 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1). Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 2016 2017 2016 Capitalized portion of net periodic pension benefit cost $ 1.0 $ 1.0 $ 3.3 $ 3.0 Capitalized portion of net periodic postretirement benefit cost 0.1 0.2 1.3 0.6 Pension Plan Funding In August 2017, the Company contributed $20.0 million to its Pension Plan. No additional contributions are expected in 2017. Postretirement Benefit Plans The Company provides certain medical and life insurance benefits for eligible retired members. Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained at least age 55 with 10 or more years of service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Eligible retirees must contribute such amount as the Company specifies from time to time toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment provisions and other limitations. OG&E charges postretirement benefit costs to expense and includes an annual amount as a component of the cost-of-service in future ratemaking proceedings. In August 2017, the Company adopted an amendment to the retiree medical plan. Effective January 1, 2018, the Company will reduce the amount of supplemental Medicare coverage for Medicare-eligible retirees, providing a fixed stipend based on current market analysis in August 2017. The Company will continue to allow those Medicare-eligible retirees to acquire coverage from a company-provided third-party administrator. The effect of these plan amendments is reflected in the Company’s September 30, 2017 Condensed Consolidated Balance Sheet as a reduction to the postretirement benefit obligation of $42.9 million . In August 2017, the Company settled the retiree life plan in its entirety and paid $26.4 million to participants in August 2017. No gain or loss was recognized upon settlement, and the effect of the settlement is reflected in the Company’s September 30, 2017 Condensed Consolidated Balance Sheet as a reduction in the benefit obligation of $27.9 million and related other comprehensive income and regulatory asset of $2.1 million .

Report of Business Segments

Report of Business Segments	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Report of Business Segments	Report of Business Segments The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy and (ii) the natural gas midstream operations segment. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables summarize the results of the Company's business segments during the three and nine months ended September 30, 2017 and 2016 . Three Months Ended September 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 716.8 $ — $ — $ — $ 716.8 Cost of sales 255.7 — — — 255.7 Other operation and maintenance 120.2 (0.8 ) (1.7 ) — 117.7 Depreciation and amortization 76.2 — 0.7 — 76.9 Taxes other than income 21.7 0.5 1.0 — 23.2 Operating income 243.0 0.3 — — 243.3 Equity in earnings of unconsolidated affiliates — 33.6 — — 33.6 Other income 24.7 — 0.3 (0.2 ) 24.8 Interest expense 34.5 — 1.6 (0.2 ) 35.9 Income tax expense (benefit) 71.7 12.6 (1.9 ) — 82.4 Net income $ 161.5 $ 21.3 $ 0.6 $ — $ 183.4 Investment in unconsolidated affiliates $ — $ 1,152.9 $ 5.2 $ — $ 1,158.1 Total assets $ 9,230.9 $ 1,503.9 $ 87.1 $ (358.2 ) $ 10,463.7 Three Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 743.9 $ — $ — $ — $ 743.9 Cost of sales 269.8 — — — 269.8 Other operation and maintenance 115.2 (0.1 ) (2.0 ) — 113.1 Depreciation and amortization 80.8 — 1.4 — 82.2 Taxes other than income 20.9 — 0.6 — 21.5 Operating income 257.2 0.1 — — 257.3 Equity in earnings of unconsolidated affiliates — 34.5 — — 34.5 Other income 6.0 — 0.3 — 6.3 Interest expense 34.3 — 1.1 — 35.4 Income tax expense (benefit) 69.0 12.1 (2.0 ) — 79.1 Net income $ 159.9 $ 22.5 $ 1.2 $ — $ 183.6 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0 Nine Months Ended September 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,759.2 $ — $ — $ — $ 1,759.2 Cost of sales 696.5 — — — 696.5 Other operation and maintenance 362.8 (0.5 ) (5.8 ) — 356.5 Depreciation and amortization 204.6 — 2.6 — 207.2 Taxes other than income 64.2 1.0 3.2 — 68.4 Operating income (loss) 431.1 (0.5 ) — — 430.6 Equity in earnings of unconsolidated affiliates — 98.6 — — 98.6 Other income (expense) 53.2 0.1 (1.0 ) (0.3 ) 52.0 Interest expense 103.7 — 4.6 (0.3 ) 108.0 Income tax expense (benefit) 116.7 38.6 (6.3 ) — 149.0 Net income $ 263.9 $ 59.6 $ 0.7 $ — $ 324.2 Investment in unconsolidated affiliates $ — $ 1,152.9 $ 5.2 $ — $ 1,158.1 Total assets $ 9,230.9 $ 1,503.9 $ 87.1 $ (358.2 ) $ 10,463.7 Nine Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,728.4 $ — $ — $ — $ 1,728.4 Cost of sales 645.4 — — — 645.4 Other operation and maintenance 356.3 7.9 (9.6 ) — 354.6 Depreciation and amortization 235.9 — 4.9 — 240.8 Taxes other than income 63.6 — 2.9 — 66.5 Operating income (loss) 427.2 (7.9 ) 1.8 — 421.1 Equity in earnings of unconsolidated affiliates — 79.5 — — 79.5 Other income (expense) 18.3 — (0.8 ) (0.2 ) 17.3 Interest expense 104.8 — 3.1 (0.2 ) 107.7 Income tax expense (benefit) 102.4 31.5 (4.0 ) — 129.9 Net income $ 238.3 $ 40.1 $ 1.9 $ — $ 280.3 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2017
Long-term Purchase Commitment [Line Items]
Commitments and Contingencies Disclosure [Text Block]	Commitments and Contingencies Except as set forth below, in Note 13 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 13 and 14 to the Company's Consolidated Financial Statements included in the Company's 2016 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 2016 Form 10-K, OG&E has a QF contract with AES-Shady Point, Inc. ("AES") whereby OG&E purchases 100 percent of the electricity generated from AES’s 320 MW facility. The QF contract expires on January 15, 2023; however, OG&E had the option beginning in July 2017 to provide notice to AES to terminate the contract in January 2018. On July 17, 2017, OG&E and AES amended the agreement to allow OG&E the ability, through July 17, 2018, to provide AES a termination notice that would terminate the agreement on January 15, 2019. 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. Compliance with these environmental standards is expected to increase the cost of conducting business. OG&E is managing several potentially material uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. Air Quality Control System On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015 to install the Dry Scrubber systems. The Dry Scrubbers are scheduled to be completed by 2019. More detail regarding the ECP can be found under "Pending Regulatory Matters" in Note 13. Other In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss, and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements. At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

Rate Matters and Regulation

Rate Matters and Regulation	9 Months Ended
	Sep. 30, 2017
Regulated Operations [Abstract]
Rate Matters and Regulation	Rate Matters and Regulation Except as set forth below, the circumstances set forth in Note 14 to the Company's Consolidated Financial Statements included in the Company's 2016 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. Completed Regulatory Matters Arkansas Rate Case Filing On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management and increased recovery of depreciation and dismantlement costs. I n May 2017, the APSC approved a settlement between OG&E and the staff of the APSC and other intervenors. The settlement provides for a $7.1 million annual rate increase and a 9.5 percent return on equity on a 50.0 percent equity capital structure. The settlement also provides that OG&E will be regulated under a formula rate rider, which should result in a more efficient process as the return on equity, depreciation rates and capital structure should not change from what is approved by the APSC in the current rate case proceeding. The formula rate rider provides for an adjustment to rates if the earned rate of return falls outside of a plus or minus 50 basis point dead-band around the allowed return on equity. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC. OG&E expects to make its first filing under the Arkansas Formula Rate Rider in October 2018. Fuel Adjustment Clause Review for Calendar Year 2015 On September 8, 2016, the OCC staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. On October 12, 2017, the OCC issued an order, finding that, for the calendar year 2015, OG&E's electric generation, purchased power and fuel procurement processes and costs were 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. Environmental Compliance Plan On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 462 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs. On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider. On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed, and OG&E seeks recovery in its rates. On April 28, 2016, the OCC approved the Dry Scrubber project. Two parties appealed the OCC's decision to the Oklahoma Supreme Court. The Company is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action. OG&E anticipates the total cost of Dry Scrubbers will be $542.4 million , including allowance for funds used during construction and capitalized ad valorem taxes. As of September 30, 2017 , OG&E had invested $352.7 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $390.0 million , including allowance for funds used during construction and capitalized ad valorem taxes and expects the project to be completed in early 2018 . As of September 30, 2017 , OG&E had invested $306.0 million in the Mustang Modernization Plan. Integrated Resource Plans In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014 but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Oklahoma by October 1, 2018 and in Arkansas by October 31, 2018. Oklahoma Rate Case Filing On December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53.0 percent . The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma. On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million , subject to refund for amounts in excess of the rates approved by the OCC. In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations included, among other things, the use of OG&E's actual capital structure of 53.0 percent equity and 47.0 percent long-term debt and a return on equity of 9.87 percent resulting in an annual increase in OG&E's revenues of $40.7 million . On March 20, 2017, the OCC held hearings and issued an order. The order results in an annual net increase of approximately $8.8 million in OG&E's rates to its Oklahoma retail customers. Although the order adopted certain recommendations set forth in the ALJ report, it differs in certain key respects. The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent , (ii) depreciation expense is reduced by approximately $28.6 million from the ALJ report or $36.4 million from current rates on an annual basis, (iii) recovery of 50.0 percent of short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause. The order maintained OG&E's existing capital structure of 53.0 percent equity and 47.0 percent long-term debt . As a result of the March 2017 order, OG&E recorded, in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates. As of September 30, 2017 , OG&E had refunded $45.6 million of the $47.5 million expected refund from the interim rate increase. Additionally, OG&E has reserved $5.6 million , pending resolution of a dispute with PUD staff, regarding recovery of certain lost revenues associated with energy efficiency incurred prior to the March 20, 2017 rate order. These lost revenues are included within the total Demand Program Rider regulatory asset balance of $38.3 million as disclosed in Note 1. OG&E is unable to predict what actions the OCC may take regarding the unrecovered lost revenue or the timing of any actions. The remaining reserve for the interim rate refund and the lost revenues reserve are included in Other Current Liabilities on the Company's Condensed Consolidated Balance Sheets. Fuel Adjustment Clause Review for Calendar Year 2016 On August 3, 2017, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2016, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. A hearing date of March 29, 2018 has been scheduled. Mustang Modernization Plan - Arkansas On August 15, 2017, OG&E filed for a determination with the APSC that the Mustang facility is in the public's interest. The filing does not seek recovery for any costs associated with the Mustang Modernization Plan, as request for recovery of costs will take place with the first formula rate filing expected to be made in October 2018. Oklahoma Rate Case Filing - 2017 OG&E intends to file a general rate case in Oklahoma with the OCC during the fourth quarter of 2017. The rate case will be based on a September 30, 2017 test year.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation, Policy [Policy Text Block]	Organization The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable, and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading. In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at September 30, 2017 and December 31, 2016 , the results of its operations for the three and nine months ended September 30, 2017 and 2016 and its cash flows for the nine months ended September 30, 2017 and 2016 have been included and are of a normal, recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring after September 30, 2017 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 nine months ended September 30, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017 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 2016 Form 10-K.
Public Utilities, Policy [Policy Text Block]	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. 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. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Equity Method Investments [Policy Text Block]	Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting. Investment in Unconsolidated Affiliate The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable; 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 September 30, 2017 as presented in Note 11. 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). September 30, December 31, 2017 2016 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year) Senior Notes $ 2,854.1 $ 3,179.4 $ 2,385.5 $ 2,657.2 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.7 9.6 9.9 9.5 OGE Energy Senior Notes 100.0 100.0 99.7 99.9
Income Tax, Policy [Policy Text Block]	Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate. The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions.
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Share Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted-average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted-average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Regulatory Assets and Liabilities [Table Text Block]	The following table is a summary of OG&E's regulatory assets and liabilities at: September 30, December 31, (In millions) 2017 2016 Regulatory Assets Current Oklahoma demand program rider under recovery (A) $ 38.3 $ 51.0 Fuel clause under recoveries 35.5 51.3 SPP cost tracker under recovery (A) 7.8 10.0 Other (A) 2.6 9.5 Total current regulatory assets $ 84.2 $ 121.8 Non-current Benefit obligations regulatory asset $ 189.0 $ 232.6 Income taxes recoverable from customers, net 76.3 62.3 Deferred storm expenses 43.3 35.7 Smart Grid 34.7 43.2 Unamortized loss on reacquired debt 12.5 13.4 Other 17.6 17.6 Total non-current regulatory assets $ 373.4 $ 404.8 Regulatory Liabilities Current Other (B) $ 3.3 $ 12.3 Total current regulatory liabilities $ 3.3 $ 12.3 Non-current Accrued removal obligations, net $ 282.0 $ 262.8 Pension tracker 40.4 35.5 Other 9.3 1.4 Total non-current regulatory liabilities $ 331.7 $ 299.7 (A) Included in Other Current Assets on the Condensed Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following table summarizes changes to the Company's asset retirement obligations during the nine months ended September 30, 2017 and 2016 . Nine Months Ended September 30, (In millions) 2017 2016 Balance at January 1 $ 69.6 $ 63.3 Accretion expense 2.3 2.1 Liabilities settled — (0.2 ) Revisions in estimated cash flows 2.4 — Balance at September 30 $ 74.3 $ 65.2
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 nine months ended September 30, 2017 and 2016 . All amounts below are presented net of tax. Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service cost Total Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) Other comprehensive income before reclassifications — — — 6.7 6.7 Amounts reclassified from accumulated other comprehensive income (loss) 2.0 — — (0.2 ) 1.8 Settlement cost — — 0.5 — 0.5 Net current period other comprehensive income 2.0 — 0.5 6.5 9.0 Balance at September 30, 2017 $ (30.1 ) $ 0.1 $ 3.2 $ 6.5 $ (20.3 ) Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net income Prior service cost Net income Prior service cost Total Balance at December 31, 2015 $ (39.2 ) $ 0.1 $ 2.5 $ 1.5 $ (35.1 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.3 — — (1.2 ) 1.1 Settlement cost 5.0 — — — 5.0 Net current period other comprehensive income (loss) 7.3 — — (1.2 ) 6.1 Balance at September 30, 2016 $ (31.9 ) $ 0.1 $ 2.5 $ 0.3 $ (29.0 )
Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]	The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and nine months ended September 30, 2017 and 2016 . 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 Comprehensive Income Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 2016 2017 2016 Amortization of Pension Plan and Restoration of Retirement Income Plan items Actuarial losses (A) $ (1.1 ) $ (1.2 ) $ (3.3 ) $ (3.5 ) Other Operation and Maintenance Expense Settlement (A) — — — (8.2 ) Other Operation and Maintenance Expense (1.1 ) (1.2 ) (3.3 ) (11.7 ) Income Before Taxes (0.5 ) (0.4 ) (1.3 ) (4.4 ) Income Tax Expense $ (0.6 ) $ (0.8 ) $ (2.0 ) $ (7.3 ) Net Income Amortization of postretirement benefit plan items Prior service credit (A) $ 0.4 $ 0.6 $ 0.4 $ 1.9 Other Operation and Maintenance Expense Settlement (A) (0.7 ) — (0.7 ) — Other Operation and Maintenance Expense (0.3 ) 0.6 (0.3 ) 1.9 Income Before Taxes — 0.2 — 0.7 Income Tax Expense $ (0.3 ) $ 0.4 $ (0.3 ) $ 1.2 Net Income Total reclassifications for the period, net of tax $ (0.9 ) $ (0.4 ) $ (2.3 ) $ (6.1 ) Net Income (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Investment in Unconsolidated 24

Investment in Unconsolidated Affiliates (Tables)	9 Months Ended
	Sep. 30, 2017
Reconciliation of Basis Difference [Line Items]
Reconciliation of Basis Difference [Table Text Block]	The following table reconciles the basis difference in Enable from December 31, 2016 to September 30, 2017 . (In millions) Basis difference as of December 31, 2016 $ 743.7 Change in Enable basis difference (0.9 ) Amortization of basis difference (8.5 ) Elimination of Enable fair value step up (12.9 ) Basis difference as of September 30, 2017 $ 721.4
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]	The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three and nine months ended September 30, 2017 and 2016 . Three Months Ended Nine Months Ended September 30, September 30, Reconciliation of Equity in Earnings of Unconsolidated Affiliates 2017 2016 2017 2016 (In millions) Enable net income $ 104.0 $ 110.1 $ 301.0 $ 230.8 Distributions senior to limited partners — (9.1 ) — (9.1 ) Differences due to timing of OGE Energy and Enable accounting close — 3.0 — (7.2 ) Enable net income used to calculate OGE Energy's equity in earnings $ 104.0 $ 104.0 $ 301.0 $ 214.5 OGE Energy's percent ownership at period end 25.7 % 26.3 % 25.7 % 26.3 % OGE Energy's portion of Enable net income $ 26.5 $ 27.3 $ 77.2 $ 55.9 Impairments recognized by Enable associated with OGE Energy's basis differences — — — 1.8 OGE Energy's share of Enable net income $ 26.5 $ 27.3 $ 77.2 $ 57.7 Amortization of basis difference 2.8 2.9 8.5 8.8 Elimination of Enable fair value step up 4.3 4.3 12.9 13.0 Equity in earnings of unconsolidated affiliates $ 33.6 $ 34.5 $ 98.6 $ 79.5
Schedule of Related Party Transactions [Table Text Block]	The following table summarizes related party transactions between OG&E and Enable during the three and nine months ended September 30, 2017 and 2016 . Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 2016 2017 2016 Operating revenues: Electricity to power electric compression assets $ 4.5 $ 3.7 $ 10.0 $ 9.0 Cost of sales: Natural gas transportation services $ 8.8 $ 8.8 $ 26.3 $ 26.3 Natural gas purchases (sales) 0.4 4.4 (0.4 ) 11.3
Summarized Balance Sheet Financial Information, Equity Method Investment [Table Text Block]	Summarized unaudited financial information for 100 percent of Enable is presented below at September 30, 2017 and December 31, 2016 and for the three and nine months ended September 30, 2017 and 2016 . September 30, December 31, Balance Sheet 2017 2016 (In millions) Current assets $ 446 $ 396 Non-current assets 10,816 10,816 Current liabilities 831 362 Non-current liabilities 2,740 3,056
Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, Income Statement 2017 2016 2017 2016 (In millions) Operating revenues $ 705 $ 620 $ 1,997 $ 1,658 Cost of natural gas and NGLs 349 268 936 717 Operating income 137 139 399 299 Net income 104 110 301 231

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value and Carrying Amount of PRM Financial Instruments [Table Text Block]	The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2017 and December 31, 2016 . September 30, December 31, 2017 2016 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year) Senior Notes $ 2,854.1 $ 3,179.4 $ 2,385.5 $ 2,657.2 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.7 9.6 9.9 9.5 OGE Energy Senior Notes 100.0 100.0 99.7 99.9

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]	The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and nine months ended September 30, 2017 and 2016 related to the Company's performance units and restricted stock . Three Months Ended September 30, Nine Months Ended September 30, (In millions) 2017 2016 2017 2016 Performance units Total shareholder return $ 1.6 $ 1.2 $ 4.9 $ 3.4 Earnings per share (1.4 ) (1.3 ) (0.2 ) (0.3 ) Total performance units 0.2 (0.1 ) 4.7 3.1 Restricted stock 0.1 — 0.1 0.1 Total compensation expense $ 0.3 $ (0.1 ) $ 4.8 $ 3.2 Income tax benefit $ 0.1 $ — $ 1.9 $ 1.3

Common Equity (Tables)

Common Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Basic and diluted earnings per share for the Company were calculated as follows: Three Months Ended September 30, Nine Months Ended September 30, (In millions except per share data) 2017 2016 2017 2016 Net income $ 183.4 $ 183.6 $ 324.2 $ 280.3 Average common shares outstanding: Basic average common shares outstanding 199.7 199.7 199.7 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.4 0.2 0.3 0.1 Diluted average common shares outstanding 200.1 199.9 200.0 199.8 Basic earnings per average common share $ 0.92 $ 0.92 $ 1.62 $ 1.40 Diluted earnings per average common share $ 0.92 $ 0.92 $ 1.62 $ 1.40 Anti-dilutive shares excluded from earnings per share calculation — — — —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows: SERIES DATE DUE AMOUNT (In millions) 0.65% - 1.03% Garfield Industrial Authority, January 1, 2025 $ 47.0 0.65% - 0.97% Muskogee Industrial Authority, January 1, 2025 32.4 0.66% - 0.98% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4

Short-Term Debt and Credit Fa29

Short-Term Debt and Credit Facilities (Tables)	9 Months Ended
	Sep. 30, 2017
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	The following table provides information regarding the Company's revolving credit agreements at September 30, 2017 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ 146.5 1.43 % (D) March 8, 2022 OG&E (C) 450.0 0.3 0.95 % (D) March 8, 2022 Total $ 900.0 $ 146.8 1.43 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2017 . (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 Postreti30

Retirement Plans and Postretirement Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2017
Defined Benefit Plan [Abstract]
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The details of net periodic benefit cost, before consideration of capitalized amounts, of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows: Net Periodic Benefit Cost Pension Plan Restoration of Retirement Three Months Ended Nine Months Ended Three Months Ended Nine Months Ended September 30, September 30, September 30, September 30, (In millions) 2017 2016 2017 2016 2017 2016 2017 2016 Service cost $ 3.9 $ 4.0 $ 11.6 $ 11.9 $ — $ — $ 0.2 $ 0.2 Interest cost 6.5 6.4 19.6 19.1 0.1 0.1 0.2 0.3 Expected return on plan assets (10.7 ) (10.4 ) (32.0 ) (31.1 ) — — — — Amortization of net loss 4.4 4.1 13.1 12.3 0.1 0.2 0.3 0.5 Amortization of unrecognized prior service cost (A) — (0.1 ) — (0.1 ) 0.1 0.1 0.1 0.1 Settlement — — — — — — — 8.7 Total net periodic benefit cost 4.1 4.0 12.3 12.1 0.3 0.4 0.8 9.8 Less: Amount paid by unconsolidated affiliates 1.2 1.3 2.9 3.8 — 0.1 — 0.3 Net periodic benefit cost (net of unconsolidated affiliates) $ 2.9 $ 2.7 $ 9.4 $ 8.3 $ 0.3 $ 0.3 $ 0.8 $ 9.5 (A) Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment. (B) In addition to the $3.2 million and $3.0 million of net periodic benefit cost recognized during the three months ended September 30, 2017 and 2016 , respectively , OG&E recognized an increase in pension expense during the three months ended September 30, 2017 and 2016 of $2.7 million and $2.4 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1) . (C) In addition to the $10.2 million and $17.8 million of net periodic benefit cost recognized during the nine months ended September 30, 2017 and 2016 , respectively , OG&E recognized the following: • an increase in pension expense during the nine months ended September 30, 2017 and 2016 of $8.5 million and $7.4 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1) ; • a deferral of pension expense during the nine months ended September 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013 ; • a deferral of pension expense during the nine months ended September 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million , in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and • a deferral of pension expense during the nine months ended September 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million . Postretirement Benefit Plans Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 (B) 2016 (B) 2017 (C) 2016 (C) Service cost $ 0.1 $ 0.2 $ 0.5 $ 0.6 Interest cost 1.6 2.4 5.9 7.1 Expected return on plan assets (0.6 ) (0.6 ) (1.7 ) (1.7 ) Amortization of net loss 0.5 0.6 1.3 1.9 Amortization of unrecognized prior service cost (A) (1.4 ) (2.1 ) (1.4 ) (6.5 ) Settlement 0.6 — 0.6 — Total net periodic benefit cost 0.8 0.5 5.2 1.4 Less: Amount paid by unconsolidated affiliates (0.1 ) — 0.5 0.1 Net periodic benefit cost (net of unconsolidated affiliates) $ 0.9 $ 0.5 $ 4.7 $ 1.3 (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 $0.9 million and $0.5 million of net periodic benefit cost recognized during the three months ended September 30, 2017 and 2016 , respectively, OG&E recognized an increase in postretirement medical expense of $1.9 million in both the three months ended September 30, 2017 and 2016 to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1). (C) In addition to the $4.7 million and $1.3 million of net periodic benefit cost recognized during the nine months ended September 30, 2017 and 2016 , respectively, OG&E recognized an increase in postretirement medical expense in the nine months ended September 30, 2017 and 2016 of $3.9 million and $5.9 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1).
Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]	Three Months Ended Nine Months Ended September 30, September 30, (In millions) 2017 2016 2017 2016 Capitalized portion of net periodic pension benefit cost $ 1.0 $ 1.0 $ 3.3 $ 3.0 Capitalized portion of net periodic postretirement benefit cost 0.1 0.2 1.3 0.6

Report of Business Segments (Ta

Report of Business Segments (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following tables summarize the results of the Company's business segments during the three and nine months ended September 30, 2017 and 2016 . Three Months Ended September 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 716.8 $ — $ — $ — $ 716.8 Cost of sales 255.7 — — — 255.7 Other operation and maintenance 120.2 (0.8 ) (1.7 ) — 117.7 Depreciation and amortization 76.2 — 0.7 — 76.9 Taxes other than income 21.7 0.5 1.0 — 23.2 Operating income 243.0 0.3 — — 243.3 Equity in earnings of unconsolidated affiliates — 33.6 — — 33.6 Other income 24.7 — 0.3 (0.2 ) 24.8 Interest expense 34.5 — 1.6 (0.2 ) 35.9 Income tax expense (benefit) 71.7 12.6 (1.9 ) — 82.4 Net income $ 161.5 $ 21.3 $ 0.6 $ — $ 183.4 Investment in unconsolidated affiliates $ — $ 1,152.9 $ 5.2 $ — $ 1,158.1 Total assets $ 9,230.9 $ 1,503.9 $ 87.1 $ (358.2 ) $ 10,463.7 Three Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 743.9 $ — $ — $ — $ 743.9 Cost of sales 269.8 — — — 269.8 Other operation and maintenance 115.2 (0.1 ) (2.0 ) — 113.1 Depreciation and amortization 80.8 — 1.4 — 82.2 Taxes other than income 20.9 — 0.6 — 21.5 Operating income 257.2 0.1 — — 257.3 Equity in earnings of unconsolidated affiliates — 34.5 — — 34.5 Other income 6.0 — 0.3 — 6.3 Interest expense 34.3 — 1.1 — 35.4 Income tax expense (benefit) 69.0 12.1 (2.0 ) — 79.1 Net income $ 159.9 $ 22.5 $ 1.2 $ — $ 183.6 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0 Nine Months Ended September 30, 2017 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,759.2 $ — $ — $ — $ 1,759.2 Cost of sales 696.5 — — — 696.5 Other operation and maintenance 362.8 (0.5 ) (5.8 ) — 356.5 Depreciation and amortization 204.6 — 2.6 — 207.2 Taxes other than income 64.2 1.0 3.2 — 68.4 Operating income (loss) 431.1 (0.5 ) — — 430.6 Equity in earnings of unconsolidated affiliates — 98.6 — — 98.6 Other income (expense) 53.2 0.1 (1.0 ) (0.3 ) 52.0 Interest expense 103.7 — 4.6 (0.3 ) 108.0 Income tax expense (benefit) 116.7 38.6 (6.3 ) — 149.0 Net income $ 263.9 $ 59.6 $ 0.7 $ — $ 324.2 Investment in unconsolidated affiliates $ — $ 1,152.9 $ 5.2 $ — $ 1,158.1 Total assets $ 9,230.9 $ 1,503.9 $ 87.1 $ (358.2 ) $ 10,463.7 Nine Months Ended September 30, 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 1,728.4 $ — $ — $ — $ 1,728.4 Cost of sales 645.4 — — — 645.4 Other operation and maintenance 356.3 7.9 (9.6 ) — 354.6 Depreciation and amortization 235.9 — 4.9 — 240.8 Taxes other than income 63.6 — 2.9 — 66.5 Operating income (loss) 427.2 (7.9 ) 1.8 — 421.1 Equity in earnings of unconsolidated affiliates — 79.5 — — 79.5 Other income (expense) 18.3 — (0.8 ) (0.2 ) 17.3 Interest expense 104.8 — 3.1 (0.2 ) 107.7 Income tax expense (benefit) 102.4 31.5 (4.0 ) — 129.9 Net income $ 238.3 $ 40.1 $ 1.9 $ — $ 280.3 Investment in unconsolidated affiliates $ — $ 1,168.0 $ — $ — $ 1,168.0 Total assets $ 8,511.5 $ 1,503.1 $ 93.3 $ (323.9 ) $ 9,784.0

Summary of Significant Accoun32

Summary of Significant Accounting Policies Equity Ownership (Details)	Sep. 30, 2017
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		Sep. 30, 2017	Dec. 31, 2016
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries		$ 35.5	$ 51.3
Current Regulatory Assets		84.2	121.8
Non-Current Regulatory Assets		373.4	404.8
Current Regulatory Liabilities		3.3	12.3
Non-Current Regulatory Liabilities		331.7	299.7
Other (B)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	3.3	12.3
Non-Current Regulatory Liabilities		9.3	1.4
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		282	262.8
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		40.4	35.5
Oklahoma demand program rider under recovery (A)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	38.3	51
SPP cost tracker under recovery (A)
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	7.8	10
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		189	232.6
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		76.3	62.3
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		43.3	35.7
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		34.7	43.2
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		12.5	13.4
Other Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	2.6	9.5
Non-Current Regulatory Assets		$ 17.6	$ 17.6
[1]	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
[2]	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.

Summary of Significant Accoun34

Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 69.6	$ 63.3
Accretion expense	2.3	2.1
Liabilities settled	0	(0.2)
Revisions in estimated cash flows	2.4	0
Balance at September 30	$ 74.3	$ 65.2

Summary of Significant Accoun35

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax		$ (20.3)	$ (29)	$ (20.3)	$ (29)	$ (29.3)	$ (35.1)
Net current period other comprehensive income				9	6.1
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				6.7
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				1.8	1.1
Other Postretirement Benefits Plan [Member]
Other Comprehensive Income (Loss), Defined Benefit Plan, Transition Asset (Obligation), Reclassification Adjustment from AOCI, before Tax	[1]	0.7	0	0.7	0
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax		(30.1)	(31.9)	(30.1)	(31.9)	(32.1)	(39.2)
Net current period other comprehensive income				2	7.3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				2	2.3
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		3.2	2.5	3.2	2.5	2.7	2.5
Net current period other comprehensive income				0.5	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] | Pension Plan [Member]
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax		0.1	0.1	0.1	0.1	0.1	0.1
Net current period other comprehensive income				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		$ 6.5	$ 0.3	6.5	0.3	$ 0	$ 1.5
Net current period other comprehensive income				6.5	(1.2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				(0.2)	(1.2)
Defined Benefit Plans Income Loss [Member] | Pension Plan [Member]
Other Comprehensive Income (Loss), before Reclassifications, before Tax				0
Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefits Plan [Member]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				0
Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefits Plan [Member]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				6.7
Pension Plan [Member] | Defined Benefit Plan Prior Service Cost [Member]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax				0
Settlement Cost [Member]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax				0.5	5
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				0	5
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				0.5	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	$ 0
[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Summary of Significant Accoun36

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) Reclassifications out of AOCI (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ (0.9)	$ (0.4)	$ (2.3)	$ (6.1)
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]	(1.1)	(1.2)	(3.3)	(3.5)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Settlement Cost, before Tax	[1]	0	0	0	(8.2)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(1.1)	(1.2)	(3.3)	(11.7)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(0.5)	(0.4)	(1.3)	(4.4)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(0.6)	(0.8)	(2)	(7.3)
Other Postretirement Benefits Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax	[1]	0.4	0.6	0.4	1.9
Other Comprehensive Income (Loss), Defined Benefit Plan, Transition Asset (Obligation), Reclassification Adjustment from AOCI, before Tax	[1]	(0.7)	0	(0.7)	0
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(0.3)	0.6	(0.3)	1.9
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		0	0.2	0	0.7
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ (0.3)	$ 0.4	$ (0.3)	$ 1.2
[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Accounting Pronouncements (Deta

Accounting Pronouncements (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)
Accounting Pronouncements [Abstract]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 22.3

Investment in Unconsolidated 38

Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	May 01, 2013
Expected Settlement Charge			$ 14.5
Limited Partner Units Owned	111		111
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.31800
Equity in earnings of unconsolidated affiliates	$ 33.6	$ 34.5	$ 98.6	$ 79.5
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	721.4		721.4		$ 743.7
Enogex LLC [Member]
Percentage of Enogex LLC Contributed						100.00%
Increase in fair value of net assets						$ 2,200
Enable Midstream Partners [Member]
Distributions from unconsolidated affiliates	$ 35.3	$ 35.3	$ 105.9	$ 105.9
OGE Holdings [Member]
Subordinated Units Held by Limited Partners of the LLC or LP.			68.2
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.70%	26.30%	25.70%	26.30%

Investment in Unconsolidated 39

Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 1.2		$ 1.2		$ 2.5
Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Proceeds from Equity Method Investment, Distribution	35.3	$ 35.3	105.9	$ 105.9
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	4.5	3.7	10	9
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	0.7	1	2.2	3.6
Employment Costs [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	6.2	6.6	23.5	21.8
Natural Gas Transportation [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	8.8	8.8	26.3	26.3
Natural Gas Purchases [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	0.4	$ 4.4	(0.4)	$ 11.3
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 2.2		$ 2.2		$ 2.7

Investment in Unconsolidated 40

Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 446	$ 396
Non-current assets	10,816	10,816
Current liabilities	831	362
Non-current liabilities	$ 2,740	$ 3,056

Investment in Unconsolidated 41

Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule of Equity Method Investments [Line Items]
Operating revenues	$ 705	$ 620	$ 1,997	$ 1,658
Cost of natural gas and NGLs	349	268	936	717
Operating income	137	139	399	299
Net income	$ 104	$ 110.1	$ 301	$ 230.8

Investment in Unconsolidated 42

Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Net income	$ 104	$ 110.1	$ 301	$ 230.8
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	721.4		721.4		$ 743.7
Timing Differences Related to Equity Method Investee Net Income	0	3	0	(7.2)
Net Income Used to Calculate Equity in Earnings	104	104	301	214.5
Proportionate Unconsolidated Affiliate Net Income	26.5	27.3	77.2	55.9
OGE Energy's share of Enable net income	26.5	27.3	77.2	57.7
Amortization of basis difference	2.8	2.9	8.5	8.8
Elimination of Enable fair value step up	4.3	4.3	12.9	13
Equity in earnings of unconsolidated affiliates	$ 33.6	$ 34.5	98.6	$ 79.5
Equity in Earnings Change in Basis Difference			$ (0.9)
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	25.70%	26.30%	25.70%	26.30%
OGE Energy [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Goodwill, Impairment Loss	$ 0	$ 0	$ 0	$ (1.8)
Preferred Partner [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 0	$ (9.1)	$ 0	$ (9.1)

Fair Value Measurements, Fair V

Fair Value Measurements, Fair Value Hierarchy (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

Fair Value Measurements Carryin

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions		Sep. 30, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Line of Credit	[1]	$ 146.8
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount		2,854.1	$ 2,385.5
Long-Term Debt, Fair Value		3,179.4	2,657.2
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		9.7	9.9
Long-Term Debt, Fair Value		9.6	9.5
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount		100	99.7
Long-Term Debt, Fair Value		100	99.9
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		$ 0	$ 0
[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2017.

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Stock-Based Compensation Activity
Income tax benefit	$ 0.1	$ 0	$ 1.9	$ 1.3
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	0.2	(0.1)	4.7	3.1
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	0.1	0	0.1	0.1
Stock Compensation Plan [Member]
Stock-Based Compensation Activity
Compensation expense	0.3	(0.1)	4.8	3.2
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	1.6	1.2	4.9	3.4
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ (1.4)	$ (1.3)	$ (0.2)	$ (0.3)

Common Equity Automatic Dividen

Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - shares	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, New Issues	0	0

Common Equity Earnings Per Shar

Common Equity Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Equity [Abstract]
Net income	$ 183.4	$ 183.6	$ 324.2	$ 280.3
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 183.4	$ 183.6	$ 324.2	$ 280.3
Basic average common shares outstanding	199.7	199.7	199.7	199.7
Contingently issuable shares (performance and restricted stock units)	0.4	0.2	0.3	0.1
Diluted average common shares outstanding	200.1	199.9	200	199.8
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share	$ 0.92	$ 0.92	$ 1.62	$ 1.40
Diluted earnings per average common share	$ 0.92	$ 0.92	$ 1.62	$ 1.40
Anti-dilutive shares excluded from earnings per share calculation	0	0	0	0

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Debt Instrument [Line Items]
Percent of Principal Amount Subject to Optional Tender	100.00%
Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 1, 2025
Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 1, 2025
Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 1, 2027
Redeemable during the next 12 months
Debt Instrument [Line Items]
Long-term Debt	$ 135.4
OG&E [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Long term debt	47
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Long term debt	32.4
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Long term debt	$ 56
Minimum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.65%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.65%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.66%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	1.03%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.97%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.98%
Senior Notes [Member] | OG&E [Member] | Series due April 1, 2047 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Long term debt	$ 300
Debt Instrument, Maturity Date	Apr. 1, 2047
Senior Notes [Member] | OG&E [Member] | Series Due July 15, 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Long term debt	$ 125
Debt Instrument, Maturity Date	Jul. 15, 2017
Senior Notes [Member] | OG&E [Member] | Series due August 15, 2047 [Member] [Domain]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.85%
Long term debt	$ 300
Debt Instrument, Maturity Date	Aug. 15, 2047

Short-Term Debt and Credit Fa49

Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Short-term debt		$ 146.5	$ 236.2
Line of Credit Facility [Abstract]
Aggregate Commitment		900
Long-term Line of Credit	[1]	$ 146.8
Weighted Average Interest Rate		1.43%
Maturity		Mar. 8, 2022
Ratio of Consolidated Debt to Consolidated Capitalization		65.00%
OGE Energy [Member]
Line of Credit Facility [Abstract]
Long-term Line of Credit	[1],[2]	$ 146.5
Weighted Average Interest Rate	[2],[3]	1.43%
Maturity	[2]	Mar. 8, 2022
OGE Energy [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[2]	$ 450
OG&E [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[4]	450
Line of Credit Facility [Abstract]
Aggregate Commitment		600
Letters of Credit Outstanding, Amount	[1],[4]	$ 0.3
Weighted Average Interest Rate	[3],[4]	0.95%
Maturity	[4]	Mar. 8, 2022
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years
Debt Restriction Maximum Letters of Credit		$ 100
Available Optional Increase of Borrowing Capacity in Credit Facility		150
Acceleration of Debt [Member] | OG&E [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		100
Uninsured Judgements [Member] | OGE Energy [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		100
Uninsured Judgements [Member] | OG&E [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		$ 100
[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2017.
[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 Postreti50

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		3 Months Ended				9 Months Ended				12 Months Ended
		Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2017		Sep. 30, 2016		Dec. 31, 2013
Defined Benefit Plan, Plan Assets, Contributions by Employer						$ 20
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment						42.9
Defined Benefit Plan, Plan Assets, Payment for Settlement						26.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		$ 3.2		$ 3		10.2		$ 17.8
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Settlement						27.9
Net Effect of Settlement on Other Comprehensive Income and Regulatory Assets						2.1
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		3.9		4		11.6		11.9
Interest cost		6.5		6.4		19.6		19.1
Expected return on plan assets		10.7		10.4		32		31.1
Defined Benefit Plan, Amortization of Gain (Loss)		4.4		4.1		13.1		12.3
Amortization of unrecognized prior service cost	[1]	0		(0.1)		0		(0.1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		4.1		4		12.3		12.1
Less: Amount paid by unconsolidated affiliates		1.2		1.3		2.9		3.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0		0		0		0		$ 22.4
Capitalized Portion of Net Periodic Benefit Cost		1		1		3.3		3
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		2.9	[1]	2.7	[1]	9.4	[2]	8.3	[2]
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0		0		0.2		0.2
Interest cost		0.1		0.1		0.2		0.3
Expected return on plan assets		0		0		0		0
Defined Benefit Plan, Amortization of Gain (Loss)		0.1		0.2		0.3		0.5
Amortization of unrecognized prior service cost	[1]	0.1		0.1		0.1		0.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		0.3		0.4		0.8		9.8
Less: Amount paid by unconsolidated affiliates		0		0.1		0		0.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0		0		0		8.7
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		0.3	[1]	0.3	[1]	0.8	[2]	9.5	[2]
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.1		0.2		0.5		0.6
Interest cost		1.6		2.4		5.9		7.1
Expected return on plan assets		0.6		0.6		1.7		1.7
Defined Benefit Plan, Amortization of Gain (Loss)		0.5		0.6		1.3		1.9
Amortization of unrecognized prior service cost	[3]	(1.4)		(2.1)		(1.4)		(6.5)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		0.8		0.5		5.2		1.4
Less: Amount paid by unconsolidated affiliates		(0.1)		0		0.5		0.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0.6		0		0.6		0
Capitalized Portion of Net Periodic Benefit Cost		0.1		0.2		1.3		0.6
Defined Benefit Plan, Net Periodic Benefit Cost, Net of Unconsolidated Affiliates		0.9	[4]	0.5	[4]	4.7	[5]	1.3	[5]
OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements		2.7		2.4		8.5		7.4
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements		$ 1.9		$ 1.9		3.9		5.9
ARKANSAS | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement						2.3
ARKANSAS | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement								$ 0.1
OGE Energy [Member] | Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement						$ 0.6
[1]	In addition to the $3.2 million and $3.0 million of net periodic benefit cost recognized during the three months ended September 30, 2017 and 2016, respectively, OG&E recognized an increase in pension expense during the three months ended September 30, 2017 and 2016 of $2.7 million and $2.4 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1).
[2]	In addition to the $10.2 million and $17.8 million of net periodic benefit cost recognized during the nine months ended September 30, 2017 and 2016, respectively, OG&E recognized the following: •an increase in pension expense during the nine months ended September 30, 2017 and 2016 of $8.5 million and $7.4 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1);•a deferral of pension expense during the nine months ended September 30, 2017 of $2.3 million related to the Arkansas jurisdictional portion of the pension settlement charge of $22.4 million in 2013;•a deferral of pension expense during the nine months ended September 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million, in accordance with the Oklahoma pension tracker regulatory liability (see Note 1); and•a deferral of pension expense during the nine months ended September 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million.
[3]	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.
[4]	In addition to the $0.9 million and $0.5 million of net periodic benefit cost recognized during the three months ended September 30, 2017 and 2016, respectively, OG&E recognized an increase in postretirement medical expense of $1.9 million in both the three months ended September 30, 2017 and 2016 to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1).
[5]	In addition to the $4.7 million and $1.3 million of net periodic benefit cost recognized during the nine months ended September 30, 2017 and 2016, respectively, OG&E recognized an increase in postretirement medical expense in the nine months ended September 30, 2017 and 2016 of $3.9 million and $5.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1).

Report of Business Segments (De

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating revenues	$ 716.8	$ 743.9	$ 1,759.2	$ 1,728.4
Cost of sales	255.7	269.8	696.5	645.4
Other operation and maintenance	117.7	113.1	356.5	354.6
Depreciation and amortization	76.9	82.2	207.2	240.8
Taxes other than income	23.2	21.5	68.4	66.5
OPERATING INCOME	243.3	257.3	430.6	421.1
Equity in earnings of unconsolidated affiliates	33.6	34.5	98.6	79.5
Other income	24.8	6.3	52	17.3
Interest expense	35.9	35.4	108	107.7
Income tax expense (benefit)	82.4	79.1	149	129.9
Net income	183.4	183.6	324.2	280.3
Investment in unconsolidated affiliates	1,158.1	1,168	1,158.1	1,168	$ 1,158.6
Total assets	10,463.7	9,784	10,463.7	9,784	$ 9,939.6
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	716.8	743.9	1,759.2	1,728.4
Cost of sales	255.7	269.8	696.5	645.4
Other operation and maintenance	120.2	115.2	362.8	356.3
Depreciation and amortization	76.2	80.8	204.6	235.9
Taxes other than income	21.7	20.9	64.2	63.6
OPERATING INCOME	243	257.2	431.1	427.2
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income	24.7	6	53.2	18.3
Interest expense	34.5	34.3	103.7	104.8
Income tax expense (benefit)	71.7	69	116.7	102.4
Net income	161.5	159.9	263.9	238.3
Investment in unconsolidated affiliates	0	0	0	0
Total assets	9,230.9	8,511.5	9,230.9	8,511.5
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	(0.8)	(0.1)	(0.5)	7.9
Depreciation and amortization	0	0	0	0
Taxes other than income	0.5	0	1	0
OPERATING INCOME	0.3	0.1	(0.5)	(7.9)
Equity in earnings of unconsolidated affiliates	33.6	34.5	98.6	79.5
Other income	0	0	0.1	0
Interest expense	0	0	0	0
Income tax expense (benefit)	12.6	12.1	38.6	31.5
Net income	21.3	22.5	59.6	40.1
Investment in unconsolidated affiliates	1,152.9	1,168	1,152.9	1,168
Total assets	1,503.9	1,503.1	1,503.9	1,503.1
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	(1.7)	(2)	(5.8)	(9.6)
Depreciation and amortization	0.7	1.4	2.6	4.9
Taxes other than income	1	0.6	3.2	2.9
OPERATING INCOME	0	0	0	1.8
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income	0.3	0.3	(1)	(0.8)
Interest expense	1.6	1.1	4.6	3.1
Income tax expense (benefit)	(1.9)	(2)	(6.3)	(4)
Net income	0.6	1.2	0.7	1.9
Investment in unconsolidated affiliates	5.2	0	5.2	0
Total assets	87.1	93.3	87.1	93.3
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Cost of sales	0	0	0	0
Other operation and maintenance	0	0	0	0
Depreciation and amortization	0	0	0	0
Taxes other than income	0	0	0	0
OPERATING INCOME	0	0	0	0
Equity in earnings of unconsolidated affiliates	0	0	0	0
Other income	(0.2)	0	(0.3)	(0.2)
Interest expense	(0.2)	0	(0.3)	(0.2)
Income tax expense (benefit)	0	0	0	0
Net income	0	0	0	0
Investment in unconsolidated affiliates	0	0	0	0
Total assets	(358.2)	(323.9)	(358.2)	(323.9)
OGE Energy [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss	$ 0	$ 0	$ 0	$ (1.8)

Rate Matters and Regulation Rat

Rate Matters and Regulation Rate Matters and Regulation (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
Public Utilities, Approved Equity Capital Structure, Percentage		53.00%
Public Utilities, Approved Debt Capital Structure, Percentage		47.00%
Amount of Interim Rate Increase Refunded		$ 45.6
Interim Rate Refund Amount		47.5
Current Regulatory Assets		84.2	$ 121.8
Dry Scrubber Project [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		352.7
Estimated Environmental Capital Costs		542.4
Mustang Modernization [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		306
Estimated Environmental Capital Costs		390
OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 92.5
Public Utilities, Requested Return on Equity, Percentage		10.25%
Public Utilities, Requested Equity Capital Structure, Percentage		53.00%
Investments Since Last Rate Case		$ 1,600
Public Utilities, Interim Rate Increase (Decrease), Amount		69.5
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 8.8
Public Utilities, Approved Return on Equity, Percentage		9.50%
Approved Depreciation Reduction from ALJ Recommendation		$ 28.6
ALJ Depreciation Recommendation		$ 36.4
Approved Recovery of Short-term Incentive Comp		50.00%
Approved Recovery of Long-term Incentive Comp		0.00%
Interim Rate Revenue Reserved		$ 5.6
ARKANSAS
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 16.5
Public Utilities, Requested Return on Equity, Percentage		10.25%
Investments Since Last Rate Case		$ 3,000
Settlement of Rate Increase		$ 7.1
Settlement of Return on Equity, Percentage		9.50%
Settlement of Equity Capital Structure, Percentage		50.00%
Administrative Law Judge [Member]
Recommended Return on Equity		9.87%
Recommended Capital Structure, Equity Percentage		53.00%
Recommended Capital Structure, Debt Percentage		47.00%
Recommended Increase (Decrease) in Revenue		$ 40.7
Oklahoma demand program rider under recovery (A)
Current Regulatory Assets	[1]	$ 38.3	$ 51
[1]	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.