OGE Energy (OGE) 10-K 23 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
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-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		199,703,952
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 6,525,558,217

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
OPERATING REVENUES
Total operating revenues	$ 2,259.2		$ 2,196.9		$ 2,453.1
COST OF SALES
Total cost of sales	880.1		865		1,106.6
OPERATING EXPENSES
Other operation and maintenance	465.6		451.6		439.6
Depreciation and amortization	322.6		307.9		281.4
Taxes other than income	87.6		91.2		88.7
Total operating expenses	875.8		850.7		809.7
Operating income (loss)	503.3		481.2		536.8
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	101.8		15.5	[1]	172.6
Allowance for equity funds used during construction	14.2		8.3		4.2
Other income	26		27		17.8
Other expense	(16.9)		(14.3)		(14.4)
Net other income (expense)	125.1		36.5		180.2
INTEREST EXPENSE
Interest on long-term debt	143.2		147.8		144.6
Allowance for borrowed funds used during construction	(7.5)		(4.2)		(2.4)
Interest on short-term debt and other interest charges	6.4		5.4		6.2
Interest expense	142.1		149		148.4
INCOME BEFORE TAXES	486.3		368.7		568.6
INCOME TAX EXPENSE	148.1		97.4		172.8
NET INCOME	$ 338.2		$ 271.3		$ 395.8
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7		199.6		199.2
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.9		199.6		199.9
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 1.69	[2]	$ 1.36	[2]	$ 1.99
DILUTED EARNINGS PER AVERAGE COMMON SHARE	1.69	[2]	1.36	[2]	1.98
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.15500		$ 1.05000		$ 0.95000
[1]	In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment.
[2]	Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income	$ 338.2	$ 271.3	$ 395.8
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $1.7, $2.2 and $1.2, respectively	2.8	2.5	1.8
Net loss arising during the period, net of tax of ($0.6), ($5.8) and ($7.0), respectively	(0.7)	(9.5)	(11.1)
Settlement cost, net of tax of $3.2, $2.9 and ($0.1), respectively	5	4.6	(0.1)
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0, $0.8 and $0.5, respectively	0	1.2	0.9
Net gain (loss) arising during the period, net of tax of $0.1, $5.6 and ($1.9), respectively	0.2	9.3	(3.1)
Amortization of prior service cost, net of tax of ($1.0), ($1.1) and ($1.1), respectively	(1.5)	(1.8)	(1.8)
Amortization of deferred interest rate swap hedging losses, net of tax of $0, $0 and $0.1, respectively	0	0	0.2
Other comprehensive income (loss), net of tax	5.8	6.3	(13.2)
Comprehensive income	$ 344	$ 277.6	$ 382.6

CONSOLIDATED STATEMENTS OF COM4

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 1.7	$ 2.2	$ 1.2
Net gain (loss) arising during the period	(0.6)	(5.8)	(7)
Settlement cost	3.2	2.9	(0.1)
Postretirement plans:
Amortization of deferred net loss	0	0.8	0.5
Net gain (loss) arising during the period	0.1	5.6	(1.9)
Amortization of prior service cost	(1)	(1.1)	(1.1)
Amortization of deferred interest rate swap hedging losses	$ 0	$ 0	$ 0.1

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 338.2	$ 271.3		$ 395.8
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	322.6	307.9		281.4
Deferred income taxes and investment tax credits	153.8	102.6		177.3
Equity in earnings of unconsolidated affiliates	(101.8)	(15.5)	[1]	(172.6)
Distributions from unconsolidated affiliates	102.3	94.1		143.7
Allowance for equity funds used during construction	(14.2)	(8.3)		(4.2)
Stock-based compensation	4.6	5.9		(2.7)
Regulatory assets	(21.4)	(9.1)		4.5
Regulatory liabilities	(11.8)	(27.5)		(4.4)
Other assets	15.4	10.4		(16.5)
Other liabilities	(18.9)	8.6		29.6
Change in certain current assets and liabilities
Accounts receivable, net	0.1	15.7		(9.4)
Accounts receivable - unconsolidated affiliates	(0.8)	3.9		6.8
Accrued unbilled revenues	(6.2)	2		3.2
Income taxes receivable	(2.2)	(1.2)		(10.4)
Fuel, materials and supplies inventories	32.4	(56.5)		20.4
Fuel clause under recoveries	(51.3)	68.3		(42.1)
Other current assets	(26.2)	(17.2)		(2.6)
Accounts payable	(45.1)	30.9		(64)
Fuel clause over recoveries	(61.3)	61.3		(0.4)
Other current liabilities	36.4	17.8		(11.8)
Net Cash Provided from Operating Activities	644.6	865.4		721.6
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(660.1)	(547.8)		(569.3)
Return of capital - equity method investments	38.8	45.2		9.5
Proceeds from sale of assets	0.9	2.5		0.7
Net Cash Used in Investing Activities	(620.4)	(500.1)		(559.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	0	0		588.9
Issuance of common stock	0	7.2		13.2
Dividends paid on common stock	(225.1)	(204.6)		(184.1)
Payment of long-term debt	(110.2)	(0.2)		(240.2)
Increase (decrease) in short-term debt	236.2	(98)		(341.6)
Net cash used in financing activities	(99.1)	(295.6)		(163.8)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(74.9)	69.7		(1.3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2	5.5		6.8
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0.3	$ 75.2		$ 5.5
[1]	In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment.

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 0.3	$ 75.2
Accounts receivable, less reserve of $1.5 and $1.4, respectively	173	173.1
Accounts receivable - unconsolidated affiliates	2.5	1.7
Accrued unbilled revenues	59.7	53.5
Income taxes receivable	19.4	17.2
Fuel inventories	79.8	113.8
Materials and supplies, at average cost	81.7	80.1
Fuel clause under recoveries	51.3	0
Other	81.8	55.6
Total current assets	549.5	570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,158.6	1,194.4
Other	73.6	70.7
Total other property and investments	1,232.2	1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,690	10,318.3
Construction work in progress	495.1	278.5
Total property, plant and equipment	11,185.1	10,596.8
Less accumulated depreciation	3,488.9	3,274.4
Net property, plant and equipment	7,696.2	7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	404.8	402.2
Other	56.9	20.7
Total deferred charges and other assets	461.7	422.9
TOTAL ASSETS	9,939.6	9,580.6
CURRENT LIABILITIES
Short-term debt	236.2	0
Accounts payable	205.4	262.5
Dividends payable	60.4	54.9
Customer deposits	77.7	77
Accrued taxes	41.3	45.9
Accrued interest	40.4	42.9
Accrued compensation	45.1	54.4
Long-term debt due within one year	224.7	110
Fuel clause over recoveries	0	61.3
Other	96	43.9
Total current liabilities	1,027.2	752.8
LONG-TERM DEBT	2,405.8	2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	274.8	299.9
Deferred income taxes	2,334.5	2,178.2
Regulatory liabilities	299.7	273.6
Other	153.8	121.3
Total deferred credits and other liabilities	3,062.8	2,873
Total liabilities	6,495.8	6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,105.8	1,101.3
Retained earnings	2,367.3	2,259.8
Accumulated other comprehensive loss, net of tax	(29.3)	(35.1)
Total stockholders' equity	3,443.8	3,326
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 9,939.6	$ 9,580.6

CONSOLIDATED BALANCE SHEETS Par

CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 1.4

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Schedule of Capitalization, Long-term Debt [Line Items]
Common stock, par value $0.01 per share; authorized 450.0 shares; and outstanding 199.7 shares and 199.7 shares, respectively	$ 2	$ 2
Premium on common stock	1,103.8	1,099.3
Retained earnings	2,367.3	2,259.8
Accumulated other comprehensive loss, net of tax	(29.3)	(35.1)
Total stockholders' equity	3,443.8	3,326
Unamortized debt expense	(15.5)	(16.8)
Total long-term debt	2,630.5	2,738.8
Less long-term debt due within one year	(224.7)	(110)
Total long-term debt (excluding debt due within one year)	2,405.8	2,628.8
Total Capitalization (including long-term debt due within one year)	6,074.3	6,064.8
Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(9.3)	(9.8)
Senior Notes [Member] | Series Due November 24, 2017 [Member] | OGE Energy [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 100	100
Debt Instrument, Interest Rate, Stated Percentage	1.38%
Senior Notes [Member] | Series Due January 15, 2016 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 0	110
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Senior Notes [Member] | Series Due July 15, 2017 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 125	125
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | Series Due September 1, 2018 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Senior Notes [Member] | Series Due January 15, 2019 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Senior Notes [Member] | Series Due July 15, 2027 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 125	125
Debt Instrument, Interest Rate, Stated Percentage	6.65%
Senior Notes [Member] | Series Due April 15, 2028 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 100	100
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | Series Due January 15, 2036 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 110	110
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Senior Notes [Member] | Series Due February 1, 2038 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 200	200
Debt Instrument, Interest Rate, Stated Percentage	6.45%
Senior Notes [Member] | Series Due June 1, 2040 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	5.85%
Senior Notes [Member] | Series Due May 15, 2041 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Senior Notes [Member] | Series Due May 1, 2043 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Senior Notes [Member] | Series Due March 15, 2044 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	4.55%
Senior Notes [Member] | Series Due December 15, 2044 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Long-term Debt [Member] | Due August 31, 2062 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 9.9	10
Debt Instrument, Interest Rate, Stated Percentage	3.70%
Debentures Subject to Mandatory Redemption [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Total long-term debt	$ 135.4
Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority Bond [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	47	47
Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority Bond Due 2025 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	32.4	32.4
Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority Bond Due 2027 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 56	$ 56

CONSOLIDATED STATEMENTS OF CAP9

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	450	450
Common Stock, Shares, Outstanding	199.7	199.7
Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Maturity Date	Jan. 1, 2025
Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Maturity Date	Jan. 1, 2025
Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Maturity Date	Jun. 1, 2027
Senior Notes [Member] | Series Due November 24, 2017 [Member] | OGE Energy [Member]
Debt Instrument, Maturity Date	Nov. 24, 2017
Debt Instrument, Interest Rate, Stated Percentage	1.38%
Senior Notes [Member] | Series Due January 15, 2016 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jan. 15, 2016
Debt Instrument, Interest Rate, Stated Percentage	5.15%
Senior Notes [Member] | Series Due July 15, 2017 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jul. 15, 2017
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | Series Due September 1, 2018 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Sep. 1, 2018
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Senior Notes [Member] | Series Due January 15, 2019 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jan. 15, 2019
Debt Instrument, Interest Rate, Stated Percentage	8.25%
Senior Notes [Member] | Series Due July 15, 2027 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jul. 15, 2027
Debt Instrument, Interest Rate, Stated Percentage	6.65%
Senior Notes [Member] | Series Due April 15, 2028 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Apr. 15, 2028
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Senior Notes [Member] | Series Due January 15, 2036 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jan. 15, 2036
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Senior Notes [Member] | Series Due February 1, 2038 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Feb. 1, 2038
Debt Instrument, Interest Rate, Stated Percentage	6.45%
Senior Notes [Member] | Series Due June 1, 2040 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Jun. 1, 2040
Debt Instrument, Interest Rate, Stated Percentage	5.85%
Senior Notes [Member] | Series Due May 15, 2041 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	May 15, 2041
Debt Instrument, Interest Rate, Stated Percentage	5.25%
Senior Notes [Member] | Series Due May 1, 2043 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	May 1, 2043
Debt Instrument, Interest Rate, Stated Percentage	3.90%
Senior Notes [Member] | Series Due March 15, 2044 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Mar. 15, 2044
Debt Instrument, Interest Rate, Stated Percentage	4.55%
Senior Notes [Member] | Series Due December 15, 2044 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Dec. 15, 2044
Debt Instrument, Interest Rate, Stated Percentage	4.00%
Long-term Debt [Member] | Due August 31, 2062 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Aug. 31, 2062
Debt Instrument, Interest Rate, Stated Percentage	3.70%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	0.07%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	0.90%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	0.83%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	0.86%

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2013	$ 3,037.1	$ 2	$ 1,071.6	$ 1,991.7	$ (28.2)
Comprehensive income (loss)
Net income	395.8	0	0	395.8	0
Other comprehensive income, net of tax	(13.2)	0	0	0	(13.2)
Dividends declared on common stock	(189.3)	0	0	(189.3)	0
Issuance of common stock	13.2	0	13.2	0	0
Stock-based compensation	0.8	0	0.8	0	0
Balance at Dec. 31, 2014	3,244.4	2	1,085.6	2,198.2	(41.4)
Comprehensive income (loss)
Net income	271.3	0	0	271.3	0
Other comprehensive income, net of tax	6.3	0	0	0	6.3
Dividends declared on common stock	(209.7)	0	0	(209.7)	0
Issuance of common stock	7.2	0	7.2	0	0
Stock-based compensation	6.5	0	6.5	0	0
Balance at Dec. 31, 2015	3,326	2	1,099.3	2,259.8	(35.1)
Comprehensive income (loss)
Net income	338.2	0	0	338.2	0
Other comprehensive income, net of tax	5.8	0	0	0	5.8
Dividends declared on common stock	(230.7)	0	0	(230.7)	0
Stock-based compensation	4.5	0	4.5	0	0
Balance at Dec. 31, 2016	$ 3,443.8	$ 2	$ 1,103.8	$ 2,367.3	$ (29.3)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Summary of Significant Accounting Policies Organization The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas . Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory , and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries, and ultimately OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control , the Company began accounting for its interest in Enable using the equity method of accounting. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. The "Distrigas" method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. The Company adopted this method in January 1996 as a result of a recommendation by the OCC Staff. The Company believes this method provides a reasonable basis for allocating common expenses. Use of Estimates In preparing the Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company's Consolidated Financial Statements. However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of the Company where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment . For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues . Cash and Cash Equivalents For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value. Allowance for Uncollectible Accounts Receivable Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in the Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.4 million at December 31, 2016 and 2015 , respectively. New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit. 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 that are considered most significant to the economic performance of Enable. The Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Consolidated Balance Sheet at December 31, 2016 . The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in the 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 Consolidated Statements of Cash Flows. Allowance for Funds Used During Construction Allowance for funds used during construction is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction, a non-cash item, is reflected as an increase to net Other Income and a reduction to Interest Expense in the Consolidated Statements of Income and as an increase to Construction Work in Progress in the Consolidated Balance Sheets. Allowance for funds used during construction rates, compounded semi-annually, were 8.2 percent , 8.1 percent and 6.9 percent for the years ended December 31, 2016 , 2015 and 2014 , respectively. The increase in the allowance for funds used during construction rates in 2016 was primarily due to short-term debt being used to finance construction projects, which caused the debt portion of allowance for funds used during construction to increase. Collection of Sales Tax In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues. Revenue Recognition General OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers. SPP Purchases and Sales OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. These results are reported as Operating Revenues or Cost of Goods Sold in its Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP. Fuel Adjustment Clauses The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. The OCC and the APSC have the authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable. Income Taxes The Company file s consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions . Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Consolidated Statements of Income. Accrued Vacation The Company accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned, but not taken. Environmental Costs Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. The Company had $13.9 million and $10.0 million in accrued environmental liabilities at December 31, 2016 and 2015 , respectively, which are included in the asset retirement obligations table.
Comprehensive Income (Loss) Note [Text Block]	Accumulated Other Comprehensive Income (Loss) The following tables summarize changes in the components of accumulated other comprehensive loss attributable to OGE Energy during 2015 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 (loss) Prior service cost Net income (loss) Prior service cost Total Balance at December 31, 2014 $ (36.8 ) $ 0.1 $ (8.0 ) $ 3.3 $ (41.4 ) Other comprehensive income (loss) before reclassifications (9.5 ) — 9.3 — (0.2 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.5 — 1.2 (1.8 ) 1.9 Settlement cost 4.6 — — — 4.6 Net current period other comprehensive income (loss) (2.4 ) — 10.5 (1.8 ) 6.3 Balance at December 31, 2015 (39.2 ) 0.1 2.5 1.5 (35.1 ) Other comprehensive income (loss) before reclassifications (0.7 ) — 0.2 — (0.5 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.8 — — (1.5 ) 1.3 Settlement cost 5.0 — — — 5.0 Net current period other comprehensive income (loss) 7.1 — 0.2 (1.5 ) 5.8 Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the years ended December 31, 2016 and 2015 . Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Statement Where Net Income is Presented Year Ended December 31, (In millions) 2016 2015 Amortization of defined benefit pension and restoration of retirement income plan items Actuarial losses $ (4.5 ) $ (4.7 ) (A) Settlement (8.2 ) (7.5 ) (A) (12.7 ) (12.2 ) Total before tax (4.9 ) (5.1 ) Tax benefit $ (7.8 ) $ (7.1 ) Net of tax Amortization of postretirement benefit plan items Actuarial losses $ — $ (2.0 ) (A) Prior service cost 2.5 2.9 (A) 2.5 0.9 Total before tax 1.0 0.3 Tax expense $ 1.5 $ 0.6 Net of tax Total reclassifications for the period $ (6.3 ) $ (6.5 ) Net of tax (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information). The amounts in accumulated other comprehensive loss at December 31, 2016 that are expected to be recognized into earnings in 2017 are as follows: (In millions) Pension Plan and Restoration of Retirement Income Plan Net loss $ (3.9 ) Postretirement Benefit Plans Net loss — Prior service cost — Total, net of tax $ (3.9 )
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations The Company has previously recorded asset retirement obligations that are being accreted over their respective lives ranging from three to 74 years. The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2016 and 2015 . (In millions) 2016 2015 Balance at January 1 $ 63.3 $ 58.6 Accretion expense 2.8 2.6 Revisions in estimated cash flows (A) 3.6 1.6 Additions — 0.9 Liabilities settled (0.1 ) (0.4 ) Balance at December 31 $ 69.6 $ 63.3 (A) Assumptions changed related to the estimated cost of asbestos abatement.
Property, Plant and Equipment Disclosure [Text Block]	Property, Plant and Equipment All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense. The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Consolidated Statements of Income. December 31, 2016 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 234.2 $ 72.3 $ 161.9 Redbud Plant (A)(B) 51 % $ 489.0 $ 121.0 $ 368.0 (A) Construction work in progress was $0.2 million and $1.8 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million . December 31, 2015 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 220.4 $ 62.8 $ 157.6 Redbud Plant (A)(B) 51 % $ 487.5 $ 101.2 $ 386.3 (A) Construction work in progress was $1.6 million and $1.3 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million . OGE Energy Consolidated The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes at: December 31, 2016 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy (holding company) Property, plant and equipment $ 117.7 $ 103.3 $ 14.4 OGE Energy property, plant and equipment 117.7 103.3 14.4 OG&E Distribution assets 3,896.2 1,221.5 2,674.7 Electric generation assets (A) 4,155.9 1,493.3 2,662.6 Transmission assets (B) 2,548.8 481.3 2,067.5 Intangible plant 85.0 43.9 41.1 Other property and equipment 381.5 145.6 235.9 OG&E property, plant and equipment 11,067.4 3,385.6 7,681.8 Total property, plant and equipment $ 11,185.1 $ 3,488.9 $ 7,696.2 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million . December 31, 2015 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy (holding company) Property, plant and equipment $ 139.0 $ 112.7 $ 26.3 OGE Energy property, plant and equipment 139.0 112.7 26.3 OG&E Distribution assets 3,728.8 1,152.8 2,576.0 Electric generation assets (A) 3,837.4 1,407.0 2,430.4 Transmission assets (B) 2,454.2 440.7 2,013.5 Intangible plant 81.0 38.0 43.0 Other property and equipment 356.4 123.2 233.2 OG&E property, plant and equipment 10,457.8 3,161.7 7,296.1 Total property, plant and equipment $ 10,596.8 $ 3,274.4 $ 7,322.4 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.5 million . The following table summarizes the Company's unamortized computer software costs. December 31 (In millions) 2016 2015 OGE Energy (holding company) $ 1.0 $ 2.4 OG&E 36.5 34.3 Total $ 37.5 $ 36.7 The following table summarizes the Company's amortization expense for computer software costs. Year ended December 31 (In millions) 2016 2015 2014 OGE Energy (holding company) $ 1.4 $ 2.0 $ 4.3 OG&E 8.0 6.9 5.2 Total $ 9.4 $ 8.9 $ 9.5 Depreciation and Amortization The provision for depreciation, which was 3.0 percent and 2.9 percent of the average depreciable utility plant for 2016 and 2015 , respectively, is provided on a straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group method. In 2017 , the provision for depreciation is projected to be 3.1 percent of the average depreciable utility plant. Amortization of intangible assets is computed using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2016 , 97.0 percent will be amortized over 16 years with the remaining 3.0 percent of the intangible plant balance at December 31, 2016 being amortized over 23.7 years. Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 37 to 59 year period.
Property, Plant and Equipment [Table Text Block]	The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes at: December 31, 2016 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy (holding company) Property, plant and equipment $ 117.7 $ 103.3 $ 14.4 OGE Energy property, plant and equipment 117.7 103.3 14.4 OG&E Distribution assets 3,896.2 1,221.5 2,674.7 Electric generation assets (A) 4,155.9 1,493.3 2,662.6 Transmission assets (B) 2,548.8 481.3 2,067.5 Intangible plant 85.0 43.9 41.1 Other property and equipment 381.5 145.6 235.9 OG&E property, plant and equipment 11,067.4 3,385.6 7,681.8 Total property, plant and equipment $ 11,185.1 $ 3,488.9 $ 7,696.2 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million . December 31, 2015 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy (holding company) Property, plant and equipment $ 139.0 $ 112.7 $ 26.3 OGE Energy property, plant and equipment 139.0 112.7 26.3 OG&E Distribution assets 3,728.8 1,152.8 2,576.0 Electric generation assets (A) 3,837.4 1,407.0 2,430.4 Transmission assets (B) 2,454.2 440.7 2,013.5 Intangible plant 81.0 38.0 43.0 Other property and equipment 356.4 123.2 233.2 OG&E property, plant and equipment 10,457.8 3,161.7 7,296.1 Total property, plant and equipment $ 10,596.8 $ 3,274.4 $ 7,322.4 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.5 million .
Inventory Disclosure [Text Block]	Fuel Inventories Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $82.4 million and $119.3 million at December 31, 2016 and 2015 , respectively. Effective May 1, 2014, the gas storage services agreement with Enable was terminated. As a result of this contract termination, approximately 5.3 Bcf of cushion gas owned by OG&E and stored on the Enable system is being directed to OG&E's power plants over a five year period during peak time of June 1 to August 31 at a rate of 11,500 MMBtu/day for a total of 1.06 Bcf per year. In 2014, approximately $11.0 million of cushion gas was reclassified from Plant-in-Service to Other Deferred Assets, representing natural gas in storage, that will be removed from storage over four years. As of December 31, 2016 , the balance of cushion gas in Fuel Inventories is $3.0 million and the balance in Other Deferred Assets is $2.7 million .
Summary of Significant Accounting Policies [Text Block]	Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. The following table is a summary of OG&E's regulatory assets and liabilities at: December 31 (In millions) 2016 2015 Regulatory Assets Current Fuel clause under recoveries $ 51.3 $ — Oklahoma demand program rider under recovery (A) 51.0 36.6 SPP cost tracker under recovery (A) 10.0 4.5 Other (A) 9.5 5.4 Total Current Regulatory Assets $ 121.8 $ 46.5 Non-Current Benefit obligations regulatory asset $ 232.6 $ 242.2 Income taxes recoverable from customers, net 62.3 56.7 Smart Grid 43.2 43.6 Deferred storm expenses 35.7 27.6 Unamortized loss on reacquired debt 13.4 14.8 Other 17.6 17.3 Total Non-Current Regulatory Assets $ 404.8 $ 402.2 Regulatory Liabilities Current Fuel clause over recoveries $ — $ 61.3 Other (B) 12.3 7.5 Total Current Regulatory Liabilities $ 12.3 $ 68.8 Non-Current Accrued removal obligations, net $ 262.8 $ 254.9 Pension tracker 35.5 17.7 Other (C) 1.4 1.0 Total Non-Current Regulatory Liabilities $ 299.7 $ 273.6 (A) Included in Other Current Assets on the Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Consolidated Balance Sheets. (C) Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities. Fuel clause under recoveries are generated from under recoveries from OG&E's customers when OG&E's cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from OG&E's customers when the amount billed to its customers exceeds OG&E's cost of fuel. OG&E's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances. OG&E recovers program costs related to the Demand and Energy Efficiency Program. An extension of the demand program rider was approved in January 2016, which allows for the recovery through December 2018 of (i) demand program costs; (ii) lost revenues associated with certain achieved energy efficiency and demand savings; (iii) performance-based incentives; and (iv) costs associated with research and development investments. OG&E recovers certain SPP costs related to base plan charges from its customers in Oklahoma through the SPP cost tracker. The benefit obligations regulatory asset is comprised of expenses recorded which are probable of future recovery and that have not yet been recognized as components of net periodic benefit cost, including net loss and prior service cost. These expenses are recorded as a regulatory asset as OG&E had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the benefit obligations regulatory asset balance to be reclassified to accumulated other comprehensive income. The following table is a summary of the components of the benefit obligations regulatory asset at: December 31 (In millions) 2016 2015 Pension Plan and Restoration of Retirement Income Plan Net loss $ 199.9 $ 214.1 Postretirement Benefit Plans Net loss 32.7 34.2 Prior service cost — (6.1 ) Total $ 232.6 $ 242.2 The following amounts in the benefit obligations regulatory asset at December 31, 2016 are expected to be recognized as components of net periodic benefit cost in 2017 : (In millions) Pension Plan and Restoration of Retirement Income Plan Net loss $ 12.4 Postretirement Benefit Plans Net loss 2.3 Total $ 14.7 Income taxes recoverable from customers, which represents income tax benefits previously used to reduce OG&E's revenues, are treated as regulatory assets and are being amortized over the estimated remaining life of the assets to which they relate. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The income tax related regulatory assets and liabilities are netted in income taxes recoverable from customers, net in the regulatory assets and liabilities table above. OG&E recovers the cost of system-wide deployment of smart grid technology and implementing the smart grid pilot program, the incremental costs for web portal access, education and providing home energy reports. These amounts are currently being recovered through a rate rider. Following a final order in the current Oklahoma general rate case, and review by the OCC Staff, the Oklahoma jurisdictional balance of the regulatory asset will be included in the fuel adjustment clause for final recovery. Costs not included in the rider are the incremental costs for web portal access, education and home energy reports, which are capped at $6.9 million , and the stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters and were accumulated during the smart grid deployment and have been included in the Smart Grid asset in the regulatory assets and liabilities table above. These costs are expected to be recovered in base rates upon final orders in the current general rate cases. OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers any additional expenses incurred over $2.7 million . OG&E expects to recover the amounts deferred each year over a five -year period in accordance with historical practice. Unamortized loss on reacquired debt is comprised of unamortized debt issuance costs related to the early retirement of OG&E's long-term debt. These amounts are recorded in interest expenses and are being amortized over the term of the long-term debt which replaced the previous long-term debt. The unamortized loss on reacquired debt is recovered as a part of OG&E's cost of capital. Accrued removal obligations, net represent asset retirement costs previously recovered from ratepayers for other than legal obligations. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate cases. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate case as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory liability in the regulatory assets and liabilities table above. 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.
Reclassifications [Text Block]	Reclassifications Certain prior-year amounts have been reclassified to conform to the current year presentation. The December 31, 2015 Consolidated Balance Sheet has been adjusted for the reclassification of $16.8 million of debt issuance costs from Total Deferred Charges and Other Assets to Long-Term Debt to be consistent with the 2016 presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," in 2016.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2016
Accounting Pronouncement [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting Pronouncements Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. The deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The Company currently expects to apply the modified retrospective transition method, but will ultimately determine its transition approach once various industry issues have been resolved. Currently, the Company is not aware of any issues that would have a material impact on the timing of revenue recognition. The Company is assessing the impact of this new guidance on its tariff-based sales, contributions in aid of construction, bundled arrangements and alternative revenue programs. At this time, the Company is evaluating the impact of the new standard on its results of operations and financial position, but believes that it will change the income statement presentation of revenues and will require new disclosures. Consolidation . In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810)." The amendments in ASU 2015-02 affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. The new standard modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities along with eliminating the presumption that a general partner should consolidate a limited partnership. The new standard is effective for fiscal years beginning after December 15, 2015. The adoption of this new standard did not result in the consolidation of any non-consolidated entities. Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between current lease accounting and Topic 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as the Company , will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance, but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 15, 2018. The new guidance must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has started evaluating its current lease contracts. The Company has not determined the amount of impact on its Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities. Investments. In March 2016, the FASB issued ASU 2016-07, "Investments-Equity Method and Joint Ventures; Simplifying the Transition to the Equity Method of Accounting (Topic 323)." The amendments in ASU 2016-07 eliminate the requirement to retroactively adopt the equity method of accounting for a qualifying equity method investment. ASU 2016-07 requires equity method investors to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendments in this ASU are effective for the fiscal years and interim periods within those fiscal years, beginning after December 15, 2016. The Company does not believe this ASU will have any effect on its Consolidated Financial Statements. Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends ASC Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements. The new guidance among other requirements will require all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Currently, tax benefits in excess of compensation cost ("windfalls") are recorded in equity, and tax deficiencies ("shortfalls") are recorded in equity to the extent of previous windfalls, and then to the income statement. This change is required to be applied prospectively to all excess tax benefits and tax deficiencies resulting from settlements after the date of adoption of the ASU 2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. The Company will prospectively adopt this standard in the first quarter of 2017 and expects a cumulative effect of approximately $24.8 million to be recorded as a deferred tax asset with the offset in retained earnings. Going forward, tax benefits in excess of compensation cost 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. Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, "Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments." The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Company does not believe this ASU will have any effect on its Consolidated Financial Statements. Simplifying the Presentation of Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03, "Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." The amendments in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability consistent with debt discounts. The Company adopted this standard and adjusted the December 31, 2015 Consolidated Balance Sheet for the reclassification of debt issuance costs from Total Deferred Charges and Other Assets to Long-Term Debt to be consistent with the December 31, 2016 presentation. Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." This standard addresses the classification of seven specific types of cash flows as follows: debt prepayment or extinguishment costs, payments for the extinguishment of zero coupon debt, payments to settle contingent consideration liabilities incurred in a business combination, proceeds from insurance claims, payments to purchase and proceeds from the settlement of company-owned life insurance, distributions from equity method investees, and cash flows related to beneficial interests retained in securitization transactions. In addition to these seven specific issues, the ASU also provides additional guidance on the application of the predominance principle when cash receipts and payments have aspects of more than one class of cash flows. The standard is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and retrospective application is required. The Company does not believe this ASU will have a material effect on its Statements of Cash Flows. Going Concern. In August 2014, the FASB defined management’s responsibility to evaluate whether substantial doubt exists about an entity’s ability to continue as a going concern. Professional auditing standards require auditors to evaluate the going concern presumption, but previously there was a lack of guidance in GAAP for financial statement preparers. ASU 2014-15, "Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern," requires management to perform a going concern evaluation effective for annual periods ending after December 15, 2016, and annual and interim periods thereafter. The Company adopted this standard in 2016 and management does not believe there is substantial doubt about the entity’s ability to continue as a going concern. Fair Value Measurement. In May 2015, the FASB issued ASU 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent." ASU 2015-07 removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and eliminates certain disclosures for those investments. The Company adopted this standard in 2016 which minimally impacted disclosures within the Retirement Plans and Postretirement Benefit Plans footnote included in this filing.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliate and Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	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. 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 deconsolidated its interest in Enogex Holdings and began accounting for its interest in Enable using the equity method of accounting. In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At December 31, 2016 , the Company owned 111.0 million common units, or 25.7 percent , of Enable's outstanding common units. Of the Company's 111.0 million common units, 68.2 million units were subordinated. The subordination period began on the closing date of Enable’s initial public offering and will extend 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. The Company anticipates that the subordination period will expire in August 2017 and will not impact future distributions that the Company receives from Enable. On February 10, 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 $141.2 million , $139.3 million and $143.7 million during the years ended December 31, 2016 , 2015 and 2014, respectively. In 2016, CenterPoint announced that it was evaluating strategic alternatives for its investment in Enable. On July 18, 2016, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided notice to the Company of CenterPoint’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner. Under the terms of the right of first offer, the Company has 30 days from receipt of a notice from CenterPoint to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint Energy Resources Corp.'s common units and subordinated units. On August 17, 2016, the Company submitted to CenterPoint a proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in Enable GP and all of the common units and subordinated units of Enable owned by CenterPoint. In accordance with the Enable partnership Agreement, CenterPoint had 30 days after the proposal was submitted to accept the Company's right of first offer proposal. As of September 17, 2016, CenterPoint had not accepted the Company's proposal, thereby rejecting it. 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 Enable GP and all of the common units and subordinated units of Enable owned by CenterPoint. If the Company's proposal is accepted by CenterPoint, and if the transaction contemplated by the proposal is in fact consummated, the Company anticipates 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 materially change as a result of such transaction, and therefore the Company would not be required to consolidate the financial results of Enable with the financial results of the Company. The Company cannot predict what action CenterPoint will take in response to the proposal, if any, and there can be no assurance that any transaction will result from the Company's proposal or that any party will enter into a definitive agreement regarding a potential transaction, including the above-referenced third party. The Company's proposal is subject to a number of customary conditions. 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, Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2016. Under these agreements, the Company charged operating costs to Enable of $4.7 million , $12.4 million and $16.8 million for December 31, 2016 , 2015 and 2014 , respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and Enable are assigned as such. Operating costs incurred for the benefit of OG&E and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method. 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, CenterPoint, the Company and Enable agreed to continue the secondment to Enable for 192 employees that participate in the Company's defined benefit and retirement plans. The Company billed Enable for reimbursement of $28.6 million , $32.7 million and $104.8 million in 2016 , 2015 and 2014 , 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 $21.4 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 of $2.7 million and $3.4 million as of December 31, 2016 and 2015 , respectively, for amounts billed for transitional services, including the cost of seconded employees. Related Party Transactions with Enable OG&E entered into a contract with Enable to provide transportation services effective May 1, 2014. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will be effective upon the conversion of units 4 and 5 at Muskogee from coal to gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2016 , 2015 and 2014 . Year Ended December 31, (In millions) 2016 2015 2014 Operating Revenues: Electricity to power electric compression assets $ 11.5 $ 13.8 $ 13.3 Cost of Sales: Natural gas transportation services $ 35.0 $ 35.0 $ 34.9 Natural gas storage services — — 4.4 Natural gas purchases/(sales) 11.2 7.6 8.7 Summarized Financial Information of Enable Summarized unaudited financial information for 100 percent of Enable is presented below as of December 31, 2016 and 2015 and for the years ended December 31, 2016 , 2015 and 2014 . Balance Sheet December 31, (In millions) 2016 2015 Current assets $ 396 $ 381 Non-current assets 10,816 10,845 Current liabilities 362 615 Non-current liabilities 3,056 3,080 Income Statement Year Ended December 31, (In millions) 2016 2015 2014 Operating revenues $ 2,272 $ 2,418 $ 3,367 Cost of natural gas and natural gas liquids 1,017 1,097 1,914 Operating income (loss) 385 (712 ) 586 Net income (loss) 290 (752 ) 530 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 Enable's 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 $101.8 million , $15.5 million and $172.6 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's investment in Enogex and its underlying equity in the net assets of Enable and is also adjusted for the elimination of the Enogex Holdings fair value adjustments. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments , as described below. The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for the years ended December 31, 2016 and 2015 . Year Ended December 31, Reconciliation of Equity in Earnings (Loss) of Unconsolidated Affiliates 2016 2015 (In millions) Enable net income (loss) $ 289.5 $ (752.0 ) Distributions senior to limited partners (9.1 ) — Differences due to timing of OGE Energy and Enable accounting close (12.1 ) 12.1 Enable net income (loss) used to calculate OGE Energy's equity in earnings $ 268.3 $ (739.9 ) OGE Energy’s percent ownership at year end 25.7 % 26.3 % OGE Energy’s portion of Enable net income (loss) $ 70.7 $ (194.4 ) Impairments recognized by Enable associated with OGE Energy’s basis differences 2.6 178.4 OGE Energy's share of Enable net income (loss) 73.3 (16.0 ) Amortization of basis difference 11.6 13.5 Elimination of Enable fair value step up 16.9 18.0 Equity in earnings of unconsolidated affiliates $ 101.8 $ 15.5 The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $743.7 million as of December 31, 2016 . The basis difference is being amortized over approximately 30 years, beginning in May 2013. The following table reconciles the basis difference in Enable from December 31, 2015 to December 31, 2016 . (In millions) Basis difference as of December 31, 2015 $ 783.5 Dilution and impairments associated with OGE Energy’s basis difference (11.3 ) Amortization of basis difference (11.6 ) Elimination of Enable fair value step up (16.9 ) Basis difference as of December 31, 2016 $ 743.7 2015 Goodwill Impairment. Enable tested its goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicated that the carrying value of goodwill may not be recoverable. Goodwill was assessed for impairment by comparing the fair value of the reporting unit with its book value, including goodwill. Subsequent to the completion of the October 1, 2014 annual test, the crude oil and natural gas industry was impacted by further commodity price declines, which consequently resulted in decreased producer activity in certain regions in which Enable operates. Based on the decline in producer activity and the forecasted impact on future periods, in addition to an increase in the weighted average cost of capital, Enable determined that the impact on its forecasted operating profits and cash flows for its gathering and processing and transportation and storage segments for the next five years would be significantly reduced. As a result, when Enable performed the first step of its annual goodwill impairment analysis as of October 1, 2015, it determined that the carrying value of the gathering and processing and transportation and storage segments exceeded fair value. Enable completed the second step of the goodwill impairment analysis comparing the implied fair value for those reporting units to the carrying amount of that goodwill and determined that goodwill for those units was completely impaired in the amount of $1.086 billion as of September 30, 2015, and wrote off all of its goodwill in the third quarter of 2015. Accordingly, the Company recorded a $108.4 million pre-tax charge in the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis differences.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt whose fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy. The following table summarizes the fair value and carrying amount of the Company's financial instruments at December 31, 2016 and 2015 . 2016 2015 December 31 (In millions) Carrying Amount Fair Carrying Amount Fair Long-Term Debt (including Long-Term Debt due within one year) Senior Notes $ 2,385.5 $ 2,657.2 $ 2,493.9 $ 2,754.6 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.9 11.3 10.0 9.2 OGE Energy Senior Notes 99.7 99.9 99.5 99.9

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2016
Stock-Based Compensation [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	Stock-Based Compensation In 2013, the Company adopted, and its shareholders approved, the Stock Incentive Plan. Under the Stock Incentive Plan, restricted stock, restricted stock units, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries. The Company has authorized the issuance of up to 7,400,000 shares under the Stock Incentive Plan. The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the year s ended December 31, 2016 , 2015 and 2014 related to the Company's performance units and restricted stock . Year ended December 31 (In millions) 2016 2015 2014 Performance units Total shareholder return $ 4.5 $ 7.6 $ 8.3 Earnings per share — 0.7 3.7 Total performance units 4.5 8.3 12.0 Restricted stock 0.1 0.1 — Total compensation expense 4.6 8.4 12.0 Less: Amount paid by unconsolidated affiliates — 0.5 3.6 Net compensation expense $ 4.6 $ 7.9 $ 8.4 Income tax benefit $ 1.8 $ 3.1 $ 3.3 The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units. In 2016 , 2015 and 2014 , there were 2,100 shares , 82,046 shares and 494,637 shares , respectively, of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock grants (net of forfeitures) and payouts of earned performance units. In 2016 , there were 901 shares of restricted stock returned to the Company to satisfy tax liabilities. Performance Units Under the Stock Incentive Plan, the Company has issued performance units which represent the value of one share of the Company's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on the Company's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of the Company's common stock based on the Company's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of the Company's Board of Directors. All of these performance units are classified as equity in the Consolidated Balance Sheet. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of the Company's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee. Performance Units – Total Shareholder Return The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends were not accrued or paid for awards prior to February 2014, and were therefore not included in the fair value calculation. Beginning with the February 2014 performance unit awards, dividends are accrued on a quarterly basis pending achievement of payout criteria, and were therefore included in the fair value calculations. Expected price volatility is based on the historical volatility of the Company's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Company's performance units based on total shareholder return. The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table. 2016 2015 2014 Number of units granted 284,211 264,454 219,106 Fair value of units granted $ 20.97 $ 31.02 $ 34.80 Expected dividend yield 3.5 % 2.6 % 2.5 % Expected price volatility 19.8 % 16.9 % 20.0 % Risk-free interest rate 0.88 % 0.91 % 0.67 % Expected life of units (in years) 2.84 2.85 2.86 Performance Units – Earnings Per Share The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of the Company's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to the Company's performance units based on earnings per share. The number of performance units granted based on earnings per share and the grant date fair value are shown in the following table. 2016 2015 2014 Number of units granted 94,735 88,156 73,037 Fair value of units granted $ 26.64 $ 33.99 $ 34.81 Restricted Stock Under the Stock Incentive Plan, the Company issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture. The fair value of the restricted stock was based on the closing market price of the Company's common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, the Company treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period on restricted stock granted prior to July 2014, and therefore dividends are included in the fair value calculation for such restricted stock granted prior to July 2014. For restricted stock granted after July 2014, dividends will only be paid on restricted stock awards that vest. Accordingly, for restricted stock granted after July 2014, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to the Company's restricted stock. The number of shares of restricted stock granted and the grant date fair value are shown in the following table. 2016 2015 2014 Shares of restricted stock granted 1,881 958 7,037 Fair value of restricted stock granted $ 29.27 $ 26.11 $ 35.71 A summary of the activity for the Company's performance units and restricted stock at December 31, 2016 and changes in 2016 are shown in the following table. Performance Units Total Shareholder Return Earnings Per Share Restricted Stock (Dollars in millions) Number Aggregate Intrinsic Value Number Aggregate Intrinsic Value Number Aggregate Intrinsic Value Units/Shares Outstanding at 12/31/15 724,058 241,470 7,623 Granted 284,211 (A) 94,735 (A) 1,881 Converted (327,988 ) (B) $ — (109,445 ) (B) $ — N/A Vested N/A N/A (4,324 ) $ 0.1 Forfeited (16,236 ) (5,410 ) (268 ) Units/Shares Outstanding at 12/31/16 664,045 $ 17.3 221,350 $ 1.9 4,912 $ 0.2 Units/Shares Fully Vested at 12/31/16 185,214 $ — 61,742 $ — (A) For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. (B) These amounts represent performance units that vested at December 31, 2015 which were settled in February 2016. A summary of the activity for the Company's non-vested performance units and restricted stock at December 31, 2016 and changes in 2016 are shown in the following table. Performance Units Total Shareholder Return Earnings Per Share Restricted Stock Number Weighted-Average Number Weighted-Average Number Weighted-Average Units/Shares Non-Vested at 12/31/15 396,943 $ 32.83 132,316 $ 34.30 7,623 $ 29.68 Granted 284,211 (A) $ 20.97 94,735 (A) $ 26.64 1,881 $ 29.27 Converted (873 ) (B) $ 33.01 (291 ) (B) $ 33.01 N/A N/A Vested (185,214 ) $ 34.82 (61,742 ) $ 34.83 (4,324 ) $ 32.98 Forfeited (16,236 ) $ 28.89 (5,410 ) $ 31.95 (268 ) $ 37.31 Units/Shares Non-Vested at 12/31/16 478,831 $ 25.16 159,608 $ 29.71 4,912 $ 31.29 Units/Shares Expected to Vest 476,920 (C) 158,975 (C) 4,912 (A) For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. (B) Units paid out under terms of plan due to the death of a participant. (C) The intrinsic value of the performance units based on total shareholder return and earnings per share is $15.3 million and $5.1 million , respectively. Fair Value of Vested Performance Units and Restricted Stock A summary of the Company's fair value for its vested performance units and restricted stock is shown in the following table. Year ended December 31 (In millions) 2016 2015 2014 Performance units Total shareholder return $ 6.4 $ 8.5 $ 9.5 Earnings per share — — 3.8 Restricted stock 0.1 0.2 0.2 Unrecognized Compensation Cost A summary of the Company's unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. December 31, 2016 Unrecognized Compensation Cost (in millions) Weighted Average to be Recognized (in years) Performance units Total shareholder return $ 5.8 1.59 Earnings per share 2.3 1.63 Total performance units 8.1 Restricted stock 0.1 1.55 Total $ 8.2

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash Flow, Supplemental Disclosures [Text Block]	Supplemental Cash Flow Information The following table discloses information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds. Year ended December 31 (In millions) 2016 2015 2014 NON-CASH INVESTING AND FINANCING ACTIVITIES Power plant long-term service agreement $ 39.5 $ 2.3 $ — SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the period for Interest (net of interest capitalized) (A) $ 141.9 $ 145.4 $ 150.8 Income taxes (net of income tax refunds) (5.9 ) (3.4 ) 0.2 (A) Net of interest capitalized of $7.5 million , $4.2 million and $2.4 million in 2016 , 2015 and 2014 , respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Taxes [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes The items comprising income tax expense are as follows: Year ended December 31 (In millions) 2016 2015 2014 Provision (Benefit) for Current Income Taxes Federal $ — $ — $ — State (5.7 ) (5.2 ) (4.5 ) Total Provision (Benefit) for Current Income Taxes (5.7 ) (5.2 ) (4.5 ) Provision for Deferred Income Taxes, net Federal 126.0 98.8 160.0 State 28.0 4.5 18.2 Total Provision for Deferred Income Taxes, net 154.0 103.3 178.2 Deferred Federal Investment Tax Credits, net (0.2 ) (0.7 ) (0.9 ) Total Income Tax Expense $ 148.1 $ 97.4 $ 172.8 The Company file s consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions . With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2013 or state and local tax examinations by tax authorities for years prior to 2012 . Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which reduce the Company's effective tax rate. The following schedule reconciles the statutory tax rates to the effective income tax rate: Year ended December 31 2016 2015 2014 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % Federal renewable energy credit (A) (6.8 ) (8.9 ) (6.7 ) Remeasurement of state deferred tax liabilities 0.9 (0.8 ) 0.4 401(k) dividends (0.6 ) (0.7 ) (0.5 ) Federal investment tax credits, net (0.8 ) (0.2 ) (0.2 ) State income taxes, net of Federal income tax benefit 1.9 0.1 1.2 Uncertain tax positions 0.1 0.7 0.5 Amortization of net unfunded deferred taxes 0.7 0.9 0.6 Other 0.1 0.3 0.1 Effective income tax rate 30.5 % 26.4 % 30.4 % (A) Represents credits associated with the production from OG&E's wind farms. The deferred tax provisions are recognized as costs in the ratemaking process by the commissions having jurisdiction over the rates charged by OG&E. The components of Deferred Income Taxes at December 31, 2016 and 2015 , respectively, were as follows: December 31 (In millions) 2016 2015 Non-Current Deferred Income Tax Liabilities, net Accelerated depreciation and other property related differences $ 2,103.2 $ 2,016.0 Investment in Enable Midstream Partners 657.3 623.4 Regulatory asset 34.4 32.7 Income taxes refundable to customers, net 24.1 22.0 Company Pension Plan 16.5 13.7 Bond redemption-unamortized costs 4.3 4.8 Derivative instruments 2.2 1.5 Federal tax credits (220.6 ) (184.4 ) State tax credits (112.2 ) (106.7 ) Postretirement medical and life insurance benefits (48.9 ) (56.2 ) Regulatory liabilities (34.6 ) (46.3 ) Net operating losses (31.7 ) (94.6 ) Asset retirement obligations (24.5 ) (22.5 ) Accrued liabilities (16.1 ) (14.0 ) Other (14.0 ) (6.6 ) Accrued vacation (3.5 ) (3.2 ) Deferred Federal investment tax credits (0.8 ) (0.9 ) Uncollectible accounts (0.6 ) (0.5 ) Non-Current Deferred Income Tax Liabilities, net $ 2,334.5 $ 2,178.2 As of December 31, 2016 , the Company has classified $13.7 million of unrecognized tax benefits as a reduction of deferred tax assets recorded. Management is currently unaware of any issues under review that could result in significant additional payments, accruals, or other material deviation from this amount. Following is a reconciliation of the Company’s total gross unrecognized tax benefits as of the years ended December 31, 2016 , 2015 , and 2014 . (In millions) 2016 2015 2014 Balance at January 1 $ 20.2 $ 16.1 $ 12.0 Tax positions related to current year: Additions 0.5 4.1 4.1 Balance at December 31 $ 20.7 $ 20.2 $ 16.1 As of December 31, 2016 , 2015 and 2014 , there are $13.5 million , $13.2 million and $10.5 million of unrecognized tax benefits that if recognized would affect the annual effective tax rate. OG&E has determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During 2016, OG&E recorded an additional reserve for this item of $0.5 million ( $0.3 million after the federal tax benefit) related to the same Oklahoma investment tax credits generated in the current year but not yet utilized due to management's determination that it is more likely than not that it will be unable to utilize these credits. Where applicable, the Company classifies income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2016 , there were no income tax-related interest or penalties recorded with regard to uncertain tax positions. Other The Company sustained Federal and state tax operating losses through 2012 caused primarily by bonus depreciation and other book versus tax temporary differences. As a result, the Company had accrued Federal and state income tax benefits carrying into 2016. As the Company can no longer carry these losses back to prior periods, these losses are being carried forward for utilization in future years which began in 2013. In addition to the tax operating losses, the Company was unable to utilize the various tax credits that were generated during these years. These tax losses and credits are being carried as deferred tax assets and will be utilized in future periods. Under current law, the Company anticipates future taxable income will be sufficient to utilize all of the losses and remaining credits before they begin to expire. The following table summarizes these carry forwards: (In millions) Carry Forward Amount Deferred Tax Asset Earliest Expiration Date Net operating losses State operating loss $ 554.7 $ 20.4 2030 Federal operating loss 32.2 11.3 2030 Federal tax credits 220.6 220.6 2029 State tax credits Oklahoma investment tax credits 135.7 88.2 N/A Oklahoma capital investment board credits 7.3 7.3 N/A Oklahoma zero emission tax credits 24.1 16.2 2020 Louisiana inventory credits 0.7 0.5 2019 The Company has generated excess tax benefits of $24.8 million related to its equity based compensation plan which have not been recognized during the time it has been in a net operating loss position. This balance is available to offset future taxable income in addition to the net operating loss balances presented above. The Company anticipates adoption of ASU 2016-09 during 2017 which will result in the value of these excess tax benefits being recorded as a deferred tax asset with an offset to retained earnings.

Common Equity

Common Equity	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Common Equity	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 in 2016 . The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2016 , there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan. Earnings Per Share Basic earnings per share is calculated by dividing net income 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. Basic and diluted earnings per share for the Company were calculated as follows: (In millions except per share data) 2016 2015 2014 Net income $ 338.2 $ 271.3 $ 395.8 Average Common Shares Outstanding Basic average common shares outstanding 199.7 199.6 199.2 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.2 — 0.7 Diluted average common shares outstanding 199.9 199.6 199.9 Basic Earnings Per Average Common Share $ 1.69 $ 1.36 $ 1.99 Diluted Earnings Per Average Common Share $ 1.69 $ 1.36 $ 1.98 Anti-dilutive shares excluded from earnings per share calculation — — — Dividend Restrictions The Company’s Certificate of Incorporation places restrictions on the amount of common stock dividends it can pay when preferred stock is outstanding. As there is no preferred stock outstanding, that restriction did not place any effective limit on the Company’s ability to pay dividends to its shareholders. Pursuant to the leverage restriction in the Company’s revolving credit agreement, the Company must maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $452.8 million of the Company’s retained earnings from being paid out in dividends. Accordingly, approximately $1.9 billion of the Company’s retained earnings as of December 31, 2016 are unrestricted for the payment of dividends. The Company utilizes receipts from its equity investment in Enable and dividends from OG&E to pay dividends to its shareholders. Enable’s partnership agreement requires that it distribute all "available cash," as defined as cash on hand at the end of a quarter after the payment of expenses and the establishment of cash reserves, and cash on hand resulting from working capital borrowings made after the end of the quarter. Pursuant to the Federal Power Act, OG&E is restricted from paying dividends from its capital accounts. Dividends are paid from retained earnings. Pursuant to the leverage restriction in OG&E’s revolving credit agreement, OG&E must also maintain a percentage of debt to total capitalization at a level that does not exceed 65 percent . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization, which results in the restriction of approximately $351.5 million of OG&E’s retained earnings from being paid out in dividends. Accordingly, approximately $1.9 billion of OG&E’s retained earnings as of December 31, 2016 are unrestricted for the payment of dividends.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Long-term Debt, Unclassified [Abstract]
Long-Term Debt	Long-Term Debt A summary of the Company's long-term debt is included in the Consolidated Statements of Capitalization. At December 31, 2016 , the Company was in compliance with all of its debt agreements. OG&E Industrial Authority Bonds OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows: SERIES DATE DUE AMOUNT (In millions) 0.05% - 0.90% Garfield Industrial Authority, January 1, 2025 $ 47.0 0.07% - 0.83% Muskogee Industrial Authority, January 1, 2025 32.4 0.05% - 0.86% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4 All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-Term Debt in the Company's Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations. Long-Term Debt Maturities Maturities of the Company's long-term debt during the next five years consist of $225.2 million , $250.1 million , $250.1 million , $0.1 million and $0.1 million in years 2017 , 2018 , 2019 , 2020 and 2021 , respectively. The Company has previously incurred costs related to debt refinancing. Unamortized loss on reacquired debt is classified as a Non-Current Regulatory Asset, unamortized debt expense and unamortized premium and discount on long-term debt is classified as Long-Term Debt in the Consolidated Balance Sheets and are being amortized over the life of the respective debt.

Short-Term Debt and Credit Faci

Short-Term Debt and Credit Facilities	12 Months Ended
	Dec. 31, 2016
Short-term Debt [Abstract]
Short-Term Debt and Credit Facilities	Short-Term Debt and Credit Facilities The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. As of December 31, 2016 , the Company had $236.2 million in short-term debt compared to no balance at December 31, 2015 . The following table provides information regarding the Company's revolving credit agreements at December 31, 2016 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 750.0 $ 236.2 0.95 % (D) December 13, 2018 (E) OG&E (C) 400.0 1.8 0.95 % (D) December 13, 2018 (E) Total $ 1,150.0 $ 238.0 0.95 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2016 . (B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit. (E) In December 2011, OGE Energy and OG&E entered into unsecured revolving credit agreement s in the aggregate of $1,150.0 million ( $750.0 million for OGE Energy and $400.0 million for OG&E ) which expire in December 2018. OGE Energy and OG&E expect to replace the existing agreements with new revolving credit agreements during 2017, under terms and conditions generally similar to the existing agreements. 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 rating s 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	12 Months Ended
	Dec. 31, 2016
Retirement Plans and Postretirement Benefit Plans [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	Retirement Plans and Postretirement Benefit Plans Pension Plan and Restoration of Retirement Income Plan It is the Company's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by the Company's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. During 2016 , the Company made a $20.0 million contribution to its Pension Plan . During 2015 , the Company did not make any contributions to its Pension Plan. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2017 . Any contribution to the Pension Plan during 2017 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. The Company could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future. In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.6 million during 2016 . During 2015, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments paid to such employees upon retirement. As a result, the Company recorded pension settlement charges of $16.2 million in the third quarter of 2015 and $5.5 million in the fourth quarter of 2015. The pension settlement charges did not increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods. The Company provides a Restoration of Retirement Income Plan to those participants in the Company's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the Federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan. Obligations and Funded Status The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2016 and 2015 . These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion which is recorded as a regulatory asset as discussed in Note 1 ) in the Company's Consolidated Balance Sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods. The benefit obligation for the Company's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for the Company's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2016 was $608.0 million and $6.1 million , respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2015 was $ 610.9 million and $ 24.6 million , respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are as follows: Pension Plan Restoration of Retirement Postretirement December 31 (In millions) 2016 2015 2016 2015 2016 2015 Change in Benefit Obligation Beginning obligations $ 680.0 $ 725.0 $ 25.1 $ 19.7 $ 225.3 $ 280.9 Service cost 15.8 16.1 0.3 1.3 0.8 1.5 Interest cost 25.5 26.1 0.4 0.7 9.5 10.3 Plan settlements — (60.7 ) (20.6 ) — — — Participants' contributions — — — — 3.6 3.4 Actuarial (gains) losses 4.7 (11.3 ) 1.8 4.0 (7.6 ) (55.1 ) Benefits paid (53.8 ) (15.2 ) — (0.6 ) (15.7 ) (15.7 ) Ending obligations $ 672.2 $ 680.0 $ 7.0 $ 25.1 $ 215.9 $ 225.3 Change in Plans' Assets Beginning fair value $ 581.7 $ 679.8 $ — $ — $ 55.3 $ 59.6 Actual return on plans' assets 48.0 (22.2 ) — — 2.0 (0.5 ) Employer contributions 20.0 — 20.6 0.6 7.9 8.5 Plan settlements — (60.7 ) (20.6 ) — — — Participants' contributions — — — — 3.6 3.4 Benefits paid (53.8 ) (15.2 ) — (0.6 ) (15.7 ) (15.7 ) Ending fair value $ 595.9 $ 581.7 $ — $ — $ 53.1 $ 55.3 Funded status at end of year $ (76.3 ) $ (98.3 ) $ (7.0 ) $ (25.1 ) $ (162.8 ) $ (170.0 ) Net Periodic Benefit Cost Pension Plan Restoration of Retirement Postretirement Benefit Plans Year ended December 31 (In millions) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Service cost $ 15.8 $ 16.1 $ 15.3 $ 0.3 $ 1.3 $ 1.1 $ 0.8 $ 1.5 $ 3.1 Interest cost 25.5 26.1 28.1 0.4 0.7 0.6 9.5 10.3 11.4 Expected return on plan assets (41.5 ) (46.0 ) (45.3 ) — — — (2.3 ) (2.4 ) (2.4 ) Amortization of net loss 16.5 18.0 14.3 0.7 0.6 0.2 2.6 13.9 12.3 Amortization of unrecognized prior service cost (A) (0.1 ) 0.4 1.7 0.1 0.1 0.2 (8.8 ) (16.5 ) (16.5 ) Curtailment — — (0.2 ) — — — — — — Settlement — 21.7 — 8.6 — — — — — Total net periodic benefit cost 16.2 36.3 13.9 10.1 2.7 2.1 1.8 6.8 7.9 Less: Amount paid by unconsolidated affiliates 5.1 4.2 3.2 0.3 0.1 0.1 0.2 1.3 1.3 Net periodic benefit cost (B) $ 11.1 $ 32.1 $ 10.7 $ 9.8 $ 2.6 $ 2.0 $ 1.6 $ 5.5 $ 6.6 (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 $22.5 million , $40.2 million and $19.3 million of net periodic benefit cost recognized in 2016 , 2015 and 2014 , respectively, OG&E recognized the following: • a change in pension expense in 2016 , 2015 and 2014 of $9.9 million , $(3.1) million and $11.2 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 asset or liability (see Note 1); • an increase in postretirement medical expense in 2016 , 2015 and 2014 of $7.9 million , $5.8 million and $5.2 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and • a deferral of pension expense in 2016 and 2015 of $0.1 million and $1.9 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.6 million and $21.7 million , respectively. (In millions) 2016 2015 2014 Capitalized portion of net periodic pension benefit cost $ 4.0 $ 5.0 $ 3.4 Capitalized portion of net periodic postretirement benefit cost 0.8 1.9 2.0 Rate Assumptions Pension Plan and Postretirement Year ended December 31 2016 2015 2014 2016 2015 2014 Discount rate 4.00 % 4.00 % 3.80 % 4.20 % 4.25 % 3.80 % Rate of return on plans' assets 7.50 % 7.50 % 7.50 % 4.00 % 4.00 % 4.00 % Compensation increases 4.20 % 4.20 % 4.20 % N/A N/A N/A Assumed health care cost trend: Initial trend N/A N/A N/A 6.75 % 6.10 % 7.85 % Ultimate trend rate N/A N/A N/A 4.50 % 4.50 % 4.48 % Ultimate trend year N/A N/A N/A 2026 2026 2028 N/A - not applicable The overall expected rate of return on plan assets assumption was 7.50 percent in both 2016 and 2015 , which was used in determining net periodic benefit cost due to recent returns on the Company's long-term investment portfolio. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to be invested for the purpose of providing benefits specified by the Pension Plan or postretirement benefit plans. This assumption is reexamined at least annually and updated as necessary. The rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans' current and expected asset allocation. The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 6.75 percent in 2017 with the rates trending downward to 4.50 percent by 2026 . A one-percentage point change in the assumed health care cost trend rate would have the following effects: ONE-PERCENTAGE POINT INCREASE Year ended December 31 (In millions) 2016 2015 2014 Effect on aggregate of the service and interest cost components $ — $ — $ — Effect on accumulated postretirement benefit obligations 0.2 0.2 0.1 ONE-PERCENTAGE POINT DECREASE Year ended December 31 (In millions) 2016 2015 2014 Effect on aggregate of the service and interest cost components $ — $ 0.1 $ 0.1 Effect on accumulated postretirement benefit obligations 0.7 0.7 0.7 Plan Investments, Policies and Strategies The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels. Projected Benefit Obligation Funded Status Thresholds <90% 95% 100% 105% 110% 115% 120% Fixed income 50% 58% 65% 73% 80% 85% 90% Equity 50% 42% 35% 27% 20% 15% 10% Total 100% 100% 100% 100% 100% 100% 100% Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below. Asset Class Target Allocation Minimum Maximum Domestic Large Cap Equity 40% 35% 60% Domestic Mid-Cap Equity 15% 5% 25% Domestic Small-Cap Equity 25% 5% 30% International Equity 20% 10% 30% The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company's members and the Company's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines. To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against: Asset Class Comparative Benchmark(s) Active Duration Fixed Income Bloomberg Barclays Aggregate Long Duration Fixed Income Duration blended Barclays Long Government/Credit & Barclays Universal Equity Index Standard & Poor's 500 Index Mid-Cap Equity Russell Midcap Index Russell Midcap Value Index Small-Cap Equity Russell 2000 Index Russell 2000 Value Index International Equity Morgan Stanley Capital Investment ACWI ex-US The fixed income managers are expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of the Company's equity, debt or other securities is prohibited. The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-US Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-US Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the United States. All of the equities which are purchased for the international portfolio are thoroughly researched. All securities are freely traded on a recognized stock exchange and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares). For all domestic equity investment managers, no more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of the Company's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of the Company's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock. Plan Investments The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2016 and 2015 . There were no Level 3 investments held by the Pension Plan at December 31, 2016 and 2015 . (In millions) December 31, 2016 Level 1 Level 2 NAV Common stocks $ 237.1 $ 237.1 $ — $ — U.S. treasury notes and bonds (A) 122.3 122.3 — — Mortgage and asset-backed securities 59.2 — 59.2 — Corporate fixed income and other securities 137.6 — 137.6 — Commingled fund (B) 23.8 — — 23.8 Foreign government bonds 5.2 — 5.2 — U.S. municipal bonds 1.9 — 1.9 — Money market fund 2.2 — — 2.2 Mutual fund 9.0 9.0 — — Futures U.S. Treasury futures (receivable) 10.7 — 10.7 — U.S. Treasury futures (payable) (2.3 ) — (2.3 ) — Cash collateral 0.3 0.3 — — Forward contracts Receivable (foreign currency) 0.2 — 0.2 — Total Plan investments $ 607.2 $ 368.7 $ 212.5 $ 26.0 Receivable from broker for securities sold — Interest and dividends receivable 3.0 Payable to broker for securities purchased (14.3 ) Total Plan assets $ 595.9 (In millions) December 31, 2015 Level 1 Level 2 NAV Common stocks $ 208.2 $ 208.2 $ — $ — U.S. treasury notes and bonds (A) 158.9 158.9 — — Mortgage-backed securities 14.5 — 14.5 — Corporate fixed income and other securities 140.2 — 140.2 — Commingled fund (B) 24.4 — — 24.4 Foreign government bonds 5.6 — 5.6 — U.S. municipal bonds 4.9 — 4.9 — Interest-bearing cash 0.4 0.4 — — Money market fund 11.7 — — 11.7 Index fund 1.8 1.8 — — Mutual fund 24.3 24.3 — — Preferred stocks 0.3 0.3 — — Futures U.S. Treasury futures (receivable) 17.6 — 17.6 — U.S. Treasury futures (payable) (12.4 ) — (12.4 ) — Forward contracts Receivable (foreign currency) 0.1 — 0.1 — Payable (foreign currency) (0.1 ) — (0.1 ) — Total Plan investments $ 600.4 $ 393.9 $ 170.4 $ 36.1 Receivable from broker for securities sold — Interest and dividends receivable 3.5 Payable to broker for securities purchased (22.2 ) Total Plan assets $ 581.7 (A) This category represents U.S. treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher. (B) This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets. The three levels defined in the fair value hierarchy and examples of each are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common and preferred stocks, U.S. treasury notes and bonds, mutual funds, index funds and interest-bearing cash. 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. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage-backed securities, a commingled fund, a common/collective trust, U.S. municipal bonds, foreign government bonds, money market fund, treasury futures contracts and forward contracts. 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 Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). Postretirement Benefit Plans In addition to providing pension benefits, 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. The Company's contribution to the medical costs for pre-65 aged eligible retirees are fixed at the 2011 level and the Company covers future annual medical inflationary cost increases up to five percent . Increases in excess of five percent annually are covered by the pre-65 aged retiree in the form of premium increases. The Company provides Medicare-eligible retirees and their Medicare-eligible spouses an annual fixed contribution to a Company-sponsored health reimbursement arrangement. Medicare-eligible retirees are able to purchase individual insurance policies supplemental to Medicare through a third-party administrator and use their health reimbursement arrangement funds for reimbursement of medical premiums and other eligible medical expenses. Plan Investments The following tables summarize the postretirement benefit plans investments that are measured at fair value on a recurring basis at December 31, 2016 and 2015 . There were no Level 2 investments held by the postretirement benefit plans at December 31, 2016 and 2015 . (In millions) December 31, 2016 Level 1 Level 3 Group retiree medical insurance contract (A) $ 44.7 $ — $ 44.7 Mutual funds investment U.S. equity investments 8.1 8.1 — Cash 0.3 0.3 — Total Plan investments $ 53.1 $ 8.4 $ 44.7 (In millions) December 31, 2015 Level 1 Level 3 Group retiree medical insurance contract (A) $ 46.8 $ — $ 46.8 Mutual funds investment U.S. equity investments 7.8 7.8 — Money market funds investment 0.7 0.7 — Total Plan investments $ 55.3 $ 8.5 $ 46.8 (A) This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans pro-rata share of the total assets in the contract. The following table summarizes the postretirement benefit plans investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3). Year ended December 31 (In millions) 2016 Group retiree medical insurance contract Beginning balance $ 46.8 Interest income 0.9 Dividend income 0.6 Net unrealized gains related to instruments held at the reporting date 0.2 Realized losses (0.1 ) Claims paid (3.7 ) Ending balance $ 44.7 Medicare Prescription Drug, Improvement and Modernization Act of 2003 The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments the Company expects to pay related to its postretirement benefit plans, including prescription drug benefits . (In millions) Gross Projected 2017 $ 14.0 2018 14.1 2019 14.1 2020 14.1 2021 14.1 After 2021 69.1 The following table summarizes the benefit payments the Company expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure the Company's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. (In millions) Projected Benefit Payments 2017 $ 48.7 2018 48.7 2019 51.9 2020 54.6 2021 55.7 After 2021 290.1 Post-Employment Benefit Plan Disabled employees receiving benefits from the Company's Group Long-Term Disability Plan are entitled to continue participating in the Company's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Company's Group Long-Term Disability Plan and their dependents, as defined in the Company's Medical Plan. The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company's Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. The Company's post-employment benefit obligation was $2.4 million and $1.5 million at December 31, 2016 and 2015 , respectively. 401(k) Plan The Company provides a 401(k) Plan. Each regular full-time employee of the Company or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of the Company or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; (ii) a contribution made on a non Roth after-tax basis; or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation. No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions, or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan. The Company match contributions vest over a three -year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates. The Company contributed $11.9 million , $11.6 million and $15.2 million in 2016 , 2015 and 2014 , respectively, to the 401(k) Plan. Deferred Compensation Plan The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace. Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan. Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2016 , those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's Common Stock. The Company accounts for the contributions related to the Company's executive officers in this plan as Accrued Benefit Obligations and the Company accounts for the contributions related to the Company's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income and the increase in the li

Report of Business Segments

Report of Business Segments	12 Months Ended
	Dec. 31, 2016
Segment Reporting Information [Line Items]
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) natural gas midstream operations segment. Other Operations primarily includes the operations of the holding company. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. The following tables summarize the results of the Company's business segments for the years ended December 31, 2016 , 2015 and 2014 . 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 2,259.2 $ — $ — $ — $ 2,259.2 Cost of sales 880.1 — — — 880.1 Other operation and maintenance 469.8 7.7 (11.9 ) — 465.6 Depreciation and amortization 316.4 — 6.2 — 322.6 Taxes other than income 84.0 — 3.6 — 87.6 Operating income (loss) 508.9 (7.7 ) 2.1 — 503.3 Equity in earnings of unconsolidated affiliates — 101.8 — — 101.8 Other income (expense) 27.7 0.1 (4.3 ) (0.2 ) 23.3 Interest expense 138.1 — 4.2 (0.2 ) 142.1 Income tax expense (benefit) 114.4 40.5 (6.8 ) — 148.1 Net income $ 284.1 $ 53.7 $ 0.4 $ — $ 338.2 Investment in unconsolidated affiliates $ — $ 1,158.6 $ — $ — $ 1,158.6 Total assets $ 8,669.4 $ 1,521.6 $ 89.0 $ (340.4 ) $ 9,939.6 Capital expenditures $ 660.1 $ — $ — $ — $ 660.1 2015 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 2,196.9 $ — $ — $ — $ 2,196.9 Cost of sales 865.0 — — — 865.0 Other operation and maintenance 444.5 7.5 (0.4 ) — 451.6 Depreciation and amortization 299.9 — 8.0 — 307.9 Taxes other than income 87.1 — 4.1 — 91.2 Operating income (loss) 500.4 (7.5 ) (11.7 ) — 481.2 Equity in earnings of unconsolidated affiliates (A) — 15.5 — — 15.5 Other income (expense) 20.0 0.4 0.9 (0.3 ) 21.0 Interest expense 146.7 — 2.6 (0.3 ) 149.0 Income tax expense (benefit) 104.8 (1.0 ) (6.4 ) — 97.4 Net income $ 268.9 $ 9.4 $ (7.0 ) $ — $ 271.3 Investment in unconsolidated affiliates $ — $ 1,194.4 $ — $ — $ 1,194.4 Total assets $ 8,525.5 $ 1,439.5 $ 174.6 $ (559.0 ) $ 9,580.6 Capital expenditures $ 551.6 $ — $ (3.8 ) $ — $ 547.8 (A) In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment. 2014 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 2,453.1 $ — $ — $ — $ 2,453.1 Cost of sales 1,106.6 — — — 1,106.6 Other operation and maintenance 453.2 1.2 (14.8 ) — 439.6 Depreciation and amortization 270.8 — 10.6 — 281.4 Taxes other than income 84.5 — 4.2 — 88.7 Operating income (loss) 538.0 (1.2 ) — — 536.8 Equity in earnings of unconsolidated affiliates — 172.6 — — 172.6 Other income (expense) 7.1 — 0.7 (0.2 ) 7.6 Interest expense 141.5 — 7.1 (0.2 ) 148.4 Income tax expense (benefit) 111.6 69.1 (7.9 ) — 172.8 Net income 292.0 102.3 1.5 — 395.8 Investment in unconsolidated affiliates $ — $ 1,318.2 $ — $ — $ 1,318.2 Total assets $ 8,248.9 $ 1,461.2 $ 128.6 $ (328.8 ) $ 9,509.9 Capital expenditures $ 565.4 $ — $ 10.8 $ (6.9 ) $ 569.3

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Operating Lease Obligations The Company has operating lease obligations expiring at various dates , primarily for OG&E railcar leases , OG&E wind farm land leases and the Company's noncancellable operating lease. Future minimum payments for noncancellable operating leases are as follows: Year ended December 31 (In millions) 2017 2018 2019 2020 2021 After 2021 Total Operating lease obligations Railcars $ 2.7 $ 1.7 $ 21.0 $ — $ — $ — $ 25.4 Wind farm land leases 2.5 2.5 2.5 2.9 2.9 43.5 56.8 Noncancellable operating lease 0.8 0.7 — — — — 1.5 Total operating lease obligations $ 6.0 $ 4.9 $ 23.5 $ 2.9 $ 2.9 $ 43.5 $ 83.7 Payments for operating lease obligations were $9.3 million , $7.7 million and $6.7 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. OG&E Railcar Lease Agreement OG&E has a noncancellable operating lease with a purchase option, covering approximately 1,250 rotary gondola railcars to transport coal from Wyoming to OG&E's coal-fired generation units. Rental payments are charged to fuel expense and are recovered through OG&E's tariffs and fuel adjustment clauses. On January 11, 2012, OG&E executed a five-year lease agreement for 135 railcars to replace railcars that have been taken out of service or destroyed. On October 14, 2014, OG&E signed a separate three-year lease effective December 2014 for 131 railcars to replace railcars that have been taken out of service or destroyed. On December 17, 2015, OG&E renewed the lease agreement effective February 1, 2016. At the end of the new lease term, which is February 1, 2019, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $18.3 million . OG&E is also required to maintain all of the railcars it has under the operating lease. OG&E Wind Farm Land Lease Agreements OG&E has operating leases related to land for its Centennial, OU Spirit and Crossroads wind farms expiring at various dates. The Centennial lease has rent escalations which increase annually based on the Consumer Price Index. The OU Spirit and Crossroads leases have rent escalations which increase after five and 10 years. Although the leases are cancellable, OG&E is required to make annual lease payments as long as the wind turbines are located on the land. OG&E does not expect to terminate the leases until the wind turbines reach the end of their useful life. Noncancellable Operating Lease On August 29, 2012, the Company executed a five-year lease agreement for office space from September 1, 2013 to August 31, 2018. This lease has rent escalations which increase after five years and allows for leasehold improvements. Other Purchase Obligations and Commitments The Company's other future purchase obligations and commitments estimated for the next five years are as follows: (In millions) 2017 2018 2019 2020 2021 Total Other purchase obligations and commitments Cogeneration capacity and fixed operation and maintenance payments $ 77.1 $ 73.9 $ 66.5 $ 54.7 $ 51.0 $ 323.2 Expected cogeneration energy payments 37.7 37.5 38.9 40.7 44.4 199.2 Minimum fuel purchase commitments 236.2 49.3 36.2 24.6 24.6 370.9 Expected wind purchase commitments 59.0 57.9 56.6 57.1 57.5 288.1 Long-term service agreement commitments 2.2 28.4 22.2 2.4 2.4 57.6 Mustang Modernization expenditures 130.4 21.9 — — — 152.3 Environmental compliance plan expenditures 169.2 63.0 8.9 0.2 — 241.3 Total other purchase obligations and commitments $ 711.8 $ 331.9 $ 229.3 $ 179.7 $ 179.9 $ 1,632.6 Public Utility Regulatory Policy Act of 1978 At December 31, 2016 , OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019 and a QF contract with AES-Shady Point, Inc. which expires on January 15, 2023. These contracts were entered into pursuant to the Public Utility Regulatory Policy Act of 1978. Stated generally, the Public Utility Regulatory Policy Act of 1978 and the regulations thereunder promulgated by the FERC require OG&E to purchase power generated in a manufacturing process from a QF. The rate for such power to be paid by OG&E was approved by the OCC. The rate generally consists of two components: one is a rate for actual electricity purchased from the QF by OG&E; the other is a capacity charge, which OG&E must pay the QF for having the capacity available. However, if no electrical power is made available to OG&E for a period of time (generally three months), OG&E's obligation to pay the capacity charge is suspended. The total cost of cogeneration payments is recoverable in rates from customers. For the 320 MWs AES-Shady Point, Inc. QF contract and the 120 MWs Oklahoma Cogeneration LLC QF contract, OG&E purchases 100 percent of the electricity generated by the QFs. For the years ended December 31, 2016 , 2015 and 2014 , OG&E made total payments to cogenerators of $124.8 million , $124.0 million and $129.4 million , respectively, of which $66.3 million , $69.5 million and $72.3 million , respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Consolidated Statements of Income as Cost of Sales. OG&E Minimum Fuel Purchase Commitments OG&E has coal contracts for purchases through December 2017. As a participant in the SPP Integrated Marketplace, OG&E now purchases a relatively small percentage of its natural gas supply through long-term agreements. Alternatively, OG&E relies on a combination of call natural gas agreements, whereby OG&E has the right but not the obligation to purchase a defined quantity of natural gas, combined with day and intra-day purchases to meet the demands of the SPP Integrated Marketplace. OG&E Wind Purchase Commitments OG&E's current wind power portfolio includes the following, in addition to the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms owned by OG&E: (i) access to up to 50 MWs of electricity generated at a wind farm near Woodward, Oklahoma from a 15-year contract OG&E entered into with FPL Energy that expires in 2018, (ii) access to up to 152 MWs of electricity generated at a wind farm in Woodward County, Oklahoma from a 20-year contract OG&E entered into with CPV Keenan that expires in 2030, (iii) access to up to 130 MWs of electricity generated at a wind farm in Dewey County, Oklahoma from a 20-year contract OG&E entered into with Edison Mission Energy that expires in 2031 and (iv) access to up to 60 MWs of electricity generated at a wind farm near Blackwell, Oklahoma from a 20-year contract OG&E entered into with NextEra Energy that expires in 2032. The following table summarizes OG&E's wind power purchases for the years ended December 31, 2016 , 2015 and 2014 . Year ended December 31 (In millions) 2016 2015 2014 CPV Keenan $ 29.2 $ 26.7 $ 28.1 Edison Mission Energy 21.1 19.7 21.3 FPL Energy 3.4 3.2 3.6 NextEra Energy 7.3 7.0 7.8 Total wind power purchased $ 61.0 $ 56.6 $ 60.8 OG&E Long-Term Service Agreement Commitments OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 4,800 factored-fired starts. On December 30, 2015, the McClain LTSA was amended to define the terms and conditions for the exchange of spare rotors between OG&E and General Electric International, Inc. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used. OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours resulting in a maximum of the earlier of 144,000 factored-fired hours or 4,500 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2028. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used. Enable Gas Transportation Agreement OG&E contracts with Enable for firm non-notice load following gas transportation services, under a five year contract. The contract will expire in April 2019. In 2016, OG&E entered into an additional gas transportation services contract with Enable which will be effective upon the conversion of units 4 and 5 at Muskogee from coal to gas. 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. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its consolidated financial position or results of operations. The Company believes, however, that it is likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. 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 the "Pending Regulatory Matters" in Note 14. Clean Power Plan On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO 2 emissions from existing fossil-fuel-fired power plants along with state-specific CO 2 reduction standards expressed as both rate-based (lbs/MWh) and mass-based (tons/yr) goals. The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed 43 percent reduction to 32 percent in the final rule. The mass-based approach for existing units calls for a 24 percent reduction by 2030 in Oklahoma. A number of states, including Oklahoma, filed lawsuits against the Clean Power Plan. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan pending resolution of challenges to the rule. The Company is unable to determine what impact the lawsuits will ultimately have on the Clean Power Plan or what impact the stay in implementation will have; however, if the Clean Power Plan survives judicial review and is implemented as written, it could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of these standards on our operations cannot be determined with certainty at this time. Siemens Contract On June 15, 2015 OG&E entered into a contract with Siemens Energy Inc. for the purchase, design and engineering of seven simple-cycle gas turbine generators for $170.3 million associated with the Mustang Modernization Plan . 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 Consolidated Financial Statements. At the present time, based on current 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	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Rate Matters and Regulation	Rate Matters and Regulation Regulation and Rates OG&E's retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, transmission activities, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the U.S. Department of Energy has jurisdiction over some of OG&E's facilities and operations. In 2016 , 86 percent of OG&E's electric revenue was subject to the jurisdiction of the OCC, eight percent to the APSC and six percent to the FERC. The OCC issued an order in 1996 authorizing OG&E to reorganize into a subsidiary of the Company. The order required that, among other things, (i) the Company permit the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E, (ii) the Company employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E's customers and (iii) the Company refrain from pledging OG&E assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of the Company and its affiliates as the FERC deems relevant to costs incurred by OG&E or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates . Completed Regulatory Matters FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule. Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities. The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement. On July 1, 2016, the Court upheld the FERC's decision requiring removal of the "right of first refusal" for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the "right of first refusal" in the SPP Membership Agreement to be anticompetitive. The Company does not believe the Court’s ruling will have any impact on existing transmission projects for which the Company has already received a notice to construct from the SPP. The Company intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV. Fuel Adjustment Clause Review for Calendar Year 2014 On July 28, 2015, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. Oklahoma Demand Program Rider Review - SmartHours Program In July 2012, OG&E filed an application with the OCC to recover certain costs associated with demand programs through the Oklahoma Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off-peak hours during the months of May through October, by offering lower rates to those customers in the off-peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation. In December 2012, the OCC issued an order approving the recovery of costs associated with the demand programs, including the lost revenues associated with the SmartHours program, subject to the PUD Staff's review. I n March 2014, the PUD Staff began their review of the demand program costs, including the lost revenues associated with the SmartHours program. On August 9, 2016, OG&E entered into a settlement agreement with the PUD Staff to resolve the recoverable amount of lost revenues associated with the SmartHours program. The settlement provides for recovery of $10.1 million per year for 2013, 2014 and 2015, for a total of $30.3 million . OG&E had recorded $36.6 million of lost revenues for 2013, 2014 and 2015. On August 16, 2016, the OCC issued an order adopting the settlement agreement. Accordingly, OG&E reduced lost revenues and the Oklahoma Demand Program Rider regulatory asset by $6.3 million . Mustang Modernization Plan - Arkansas On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility. Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas. The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings. In July 2016, OG&E filed a motion to dismiss this proceeding and in August, the APSC approved the dismissal. OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service. Pending Regulatory Matters Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates. Environmental Compliance Plan On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 400 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 $547.5 million , including allowance for funds used during construction and capitalized ad valorem taxes. As of December 31, 2016 , OG&E had invested $208.7 million of construction work in progress on the Dry Scrubbers. OG&E anticipates the total cost for the Mustang Modernization Plan will be $424.9 million and expects the project to be completed in late 2017. As of December 31, 2016 , OG&E had invested $187.8 million on 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 Arkansas by October 1, 2017 and in Oklahoma by October 1, 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 percent . The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million . Each 0.25 percent change in the requested return on equity affects the requested rate increase by approximately $9.0 million . In late March 2016, the PUD Staff and other intervenors filed testimony in the case. The PUD Staff recommended a $6.1 million annual rate increase based on a return on equity of 9.25 percent and a common equity percentage of 53 percent . Included in the PUD Staff's recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement. The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent , as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent . Included in the Oklahoma Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement. The Oklahoma Industrial Energy Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent . Included in the Oklahoma Industrial Energy Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement. On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million which is subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case. As of December 31, 2016, the Company has recorded $39.0 million of revenues from the interim rate increase and has reserved $33.7 million of that revenue. In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations include, among other things, the use of OG&E's actual capital structure of 53 percent equity and 47 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 . The parties provided comments on the ALJ's report in early January 2017, and the OCC held hearings in early February 2017. The Company is unable to predict what action the OCC will take, or the timing of such action. 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 costs, and increased recovery of depreciation and dismantlement costs. A hearing in this matter is scheduled for the second quarter of 2017. Fuel Adjustment Clause Review for Calendar Year 2015 On September 8, 2016, the OCC Staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. A hearing in this Cause will be held on March 30, 2017.

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Quarterly Financial Information [Text Block]	Quarterly Financial Data (Unaudited) Due to the seasonal fluctuations and other factors of the Company's businesses, the operating results for interim periods are not necessarily indicative of the results that may be expected for the year. In the Company's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows: Quarter ended ( In millions, except per share data) March 31 June 30 September 30 December 31 Total Operating revenues 2016 $ 433.1 $ 551.4 $ 743.9 $ 530.8 $ 2,259.2 2015 $ 480.1 $ 549.9 $ 719.8 $ 447.1 $ 2,196.9 Operating income 2016 $ 37.9 $ 125.9 $ 257.3 $ 82.2 $ 503.3 2015 $ 56.4 $ 127.2 $ 250.8 $ 46.8 $ 481.2 Net income 2016 $ 25.2 $ 71.5 $ 183.6 $ 57.9 $ 338.2 2015 $ 43.2 $ 87.5 $ 111.2 $ 29.4 $ 271.3 Basic earnings per average common share (A) 2016 $ 0.13 $ 0.35 $ 0.92 $ 0.29 $ 1.69 2015 $ 0.22 $ 0.44 $ 0.55 $ 0.15 $ 1.36 Diluted earnings per average common share (A) 2016 $ 0.13 $ 0.35 $ 0.92 $ 0.29 $ 1.69 2015 $ 0.22 $ 0.44 $ 0.55 $ 0.15 $ 1.36 (A) Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

Schedule II

Schedule II	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]	SCHEDULE II - Valuation and Qualifying Accounts Additions Description Balance at Beginning of Period Charged to Costs and Expenses Deductions (A) Balance at End of Period (In millions) Balance at December 31, 2014 Reserve for Uncollectible Accounts $ 1.9 $ 2.3 $ 2.6 $ 1.6 Balance at December 31, 2015 Reserve for Uncollectible Accounts $ 1.6 $ 2.4 $ 2.6 $ 1.4 Balance at December 31, 2016 Reserve for Uncollectible Accounts $ 1.4 $ 2.5 $ 2.4 $ 1.5 (A) Uncollectible accounts receivable written off, net of recoveries.

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation, Policy [Policy Text Block]	Organization The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas . Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory , and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries, and ultimately OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerging crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.
Public Utilities, Policy [Policy Text Block]	Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When, in management's judgment, future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates In preparing the Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company's Consolidated Financial Statements. However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management's opinion, the areas of the Company where the most significant judgment is exercised includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment . For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues .
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Allowance for Uncollectible Accounts Receivable, Policy	Customer balances are generally written off if not collected within six months after the final billing date. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. Also, a portion of the uncollectible provision related to fuel within the Oklahoma jurisdiction is being recovered through the fuel adjustment clause. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Consolidated Balance Sheets and is included in the Other Operation and Maintenance Expense on the Consolidated Statements of Income. The allowance for uncollectible accounts receivable was $1.5 million and $1.4 million at December 31, 2016 and 2015 , respectively. New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers whose outside credit scores indicate an elevated risk are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, customers will be required to provide a security deposit.
Inventory, Policy [Policy Text Block]	Fuel Inventories Fuel inventories for the generation of electricity consist of coal, natural gas and oil. OG&E uses the weighted-average cost method of accounting for inventory that is physically added to or withdrawn from storage or stockpiles. The amount of fuel inventory was $82.4 million and $119.3 million at December 31, 2016 and 2015 , respectively.
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment All property, plant and equipment is recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction. Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance net of any salvage proceeds is recorded as a loss in the Consolidated Statements of Income as Other Expense. Repair and replacement of minor items of property are included in the Consolidated Statements of Income as Other Operation and Maintenance Expense.
Depreciation and Amortization, Policy [Policy Text Block]	Depreciation and Amortization The provision for depreciation, which was 3.0 percent and 2.9 percent of the average depreciable utility plant for 2016 and 2015 , respectively, is provided on a straight-line method over the estimated service life of the utility assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for all other plant, and is based on the average life group method. In 2017 , the provision for depreciation is projected to be 3.1 percent of the average depreciable utility plant. Amortization of intangible assets is computed using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2016 , 97.0 percent will be amortized over 16 years with the remaining 3.0 percent of the intangible plant balance at December 31, 2016 being amortized over 23.7 years. Amortization of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life of the acquired asset. Plant acquisition adjustments include $148.3 million for the Redbud Plant, which is being amortized over a 27 year life and $3.3 million for certain transmission substation facilities in OG&E's service territory, which are being amortized over a 37 to 59 year period.
Equity Method Investments, Policy [Policy 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 that are considered most significant to the economic performance of Enable. The Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Consolidated Balance Sheet at December 31, 2016 . The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in the 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 Consolidated Statements of Cash Flows.
Asset Retirement Obligations, Policy [Policy Text Block]	Asset Retirement Obligations The Company has previously recorded asset retirement obligations that are being accreted over their respective lives ranging from three to 74 years.
Allowance for Funds Used During Construction, Policy [Policy Text Block]	Allowance for Funds Used During Construction Allowance for funds used during construction is calculated according to the FERC pronouncements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction, a non-cash item, is reflected as an increase to net Other Income and a reduction to Interest Expense in the Consolidated Statements of Income and as an increase to Construction Work in Progress in the Consolidated Balance Sheets. Allowance for funds used during construction rates, compounded semi-annually, were 8.2 percent , 8.1 percent and 6.9 percent for the years ended December 31, 2016 , 2015 and 2014 , respectively.
Collection of Sales Tax, Policy [Policy Text Block]	Collection of Sales Tax In the normal course of its operations, OG&E collects sales tax from its customers. OG&E records a current liability for sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. OG&E excludes the sales tax collected from its operating revenues.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition General OG&E recognizes revenue from electric sales when power is delivered to customers. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Operating Revenues on the Consolidated Statements of Income based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers. SPP Purchases and Sales OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. These results are reported as Operating Revenues or Cost of Goods Sold in its Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP.
Fuel Adjustment Clauses, Policy [Policy Text Block]	Fuel Adjustment Clauses The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC and the APSC. The OCC and the APSC have the authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.
Income Taxes, Policy [Policy Text Block]	Income Taxes The Company file s consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions . Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carry forwards and net operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company recognizes interest related to unrecognized tax benefits in Interest Expense and recognizes penalties in Other Expense in the Consolidated Statements of Income.
Accrued Vacation, Policy [Policy Text Block]	Accrued Vacation The Company accrues vacation pay monthly by establishing a liability for vacation earned. Vacation may be taken as earned and is charged against the liability. At the end of each year, the liability represents the amount of vacation earned, but not taken.
Environmental Costs, Policy [Policy Text Block]	Environmental Costs Accruals for environmental costs are recognized when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are charged to expense or deferred as a regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future operations. Where environmental expenditures relate to facilities currently in use, such as pollution control equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior experience, assessments and current technology. Accrued obligations are regularly adjusted as environmental assessments and estimates are revised, and remediation efforts proceed. For sites where OG&E has been designated as one of several potentially responsible parties, the amount accrued represents OG&E's estimated share of the cost. The Company had $13.9 million and $10.0 million in accrued environmental liabilities at December 31, 2016 and 2015 , respectively, which are included in the asset retirement obligations table.
Fair Value of Financial Instruments, Policy [Policy Text Block]	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 fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt whose fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.
Share-based Compensation, Option and Incentive Plans, Policy [Policy Text Block]	Performance Units – Earnings Per Share The fair value of the performance units based on earnings per share is based on grant date fair value which is equivalent to the price of one share of the Company's common stock on the date of grant. The fair value of performance units based on earnings per share varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. The Company reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to the Company's performance units based on earnings per share. Restricted Stock Under the Stock Incentive Plan, the Company issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to the Company or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture. The fair value of the restricted stock was based on the closing market price of the Company's common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a primarily three-year vesting period. Also, the Company treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period on restricted stock granted prior to July 2014, and therefore dividends are included in the fair value calculation for such restricted stock granted prior to July 2014. For restricted stock granted after July 2014, dividends will only be paid on restricted stock awards that vest. Accordingly, for restricted stock granted after July 2014, only the present value of dividends expected to vest are included in the fair value calculations. The expected life of the restricted stock is based on the non-vested period since inception of the primarily three-year award cycle. There are no post-vesting restrictions related to the Company's restricted stock. Performance Units Under the Stock Incentive Plan, the Company has issued performance units which represent the value of one share of the Company's common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Stock Incentive Plan). Each performance unit is subject to forfeiture if the recipient terminates employment with the Company or a subsidiary prior to the end of the primarily three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant's number of full months of service during the award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The performance units granted based on total shareholder return are contingently awarded and will be payable in shares of the Company's common stock subject to the condition that the number of performance units, if any, earned by the employees upon the expiration of a primarily three-year award cycle (i.e., three-year cliff vesting period) is dependent on the Company's total shareholder return ranking relative to a peer group of companies. The performance units granted based on earnings per share are contingently awarded and will be payable in shares of the Company's common stock based on the Company's earnings per share growth over a primarily three-year award cycle (i.e., three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of the Company's Board of Directors. All of these performance units are classified as equity in the Consolidated Balance Sheet. If there is no or only a partial payout for the performance units at the end of the award cycle, the unearned performance units are cancelled. Payout requires approval of the Compensation Committee of the Company's Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee. Performance Units – Total Shareholder Return The fair value of the performance units based on total shareholder return was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the primarily three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends were not accrued or paid for awards prior to February 2014, and were therefore not included in the fair value calculation. Beginning with the February 2014 performance unit awards, dividends are accrued on a quarterly basis pending achievement of payout criteria, and were therefore included in the fair value calculations. Expected price volatility is based on the historical volatility of the Company's common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the award cycle. There are no post-vesting restrictions related to the Company's performance units based on total shareholder return.
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Share Basic earnings per share is calculated by dividing net income 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.
Pension and Other Postretirement Plans, Policy [Policy Text Block]	The Company provides a Restoration of Retirement Income Plan to those participants in the Company's Pension Plan whose benefits are subject to certain limitations of the Code. Participants in the Restoration of Retirement Income Plan receive the same benefits that they would have received under the Company's Pension Plan in the absence of limitations imposed by the Federal tax laws. The Restoration of Retirement Income Plan is intended to be an unfunded plan. Pension Plan and Restoration of Retirement Income Plan It is the Company's policy to fund the Pension Plan on a current basis based on the net periodic pension expense as determined by the Company's actuarial consultants. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. During 2016 , the Company made a $20.0 million contribution to its Pension Plan . During 2015 , the Company did not make any contributions to its Pension Plan. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2017 . Any contribution to the Pension Plan during 2017 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. The Company could be required to make additional contributions if the value of its pension trust and postretirement benefit plan trust assets are adversely impacted by a major market disruption in the future. The three levels defined in the fair value hierarchy and examples of each are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible by the Pension Plan at the measurement date. Instruments classified as Level 1 include investments in common and preferred stocks, U.S. treasury notes and bonds, mutual funds, index funds and interest-bearing cash. 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. Instruments classified as Level 2 include corporate fixed income and other securities, mortgage-backed securities, a commingled fund, a common/collective trust, U.S. municipal bonds, foreign government bonds, money market fund, treasury futures contracts and forward contracts. 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 Plan's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). Postretirement Benefit Plans In addition to providing pension benefits, 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. The postretirement benefit plans Level 3 investment includes an investment in a group retiree medical insurance contract. The unobservable input included in the valuation of the contract includes the approach for determining the allocation of the postretirement benefit plans pro-rata share of the total assets in the contract.
Postemployment Benefit Plans, Policy [Policy Text Block]	Post-Employment Benefit Plan Disabled employees receiving benefits from the Company's Group Long-Term Disability Plan are entitled to continue participating in the Company's Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in the Company's Group Long-Term Disability Plan and their dependents, as defined in the Company's Medical Plan. The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from the Company's Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. The Company's post-employment benefit obligation was $2.4 million and $1.5 million at December 31, 2016 and 2015 , respectively.
Plan Investments, Policies and Strategies, Policy [Policy Text Block]	Plan Investments, Policies and Strategies The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels. Projected Benefit Obligation Funded Status Thresholds <90% 95% 100% 105% 110% 115% 120% Fixed income 50% 58% 65% 73% 80% 85% 90% Equity 50% 42% 35% 27% 20% 15% 10% Total 100% 100% 100% 100% 100% 100% 100% Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below. Asset Class Target Allocation Minimum Maximum Domestic Large Cap Equity 40% 35% 60% Domestic Mid-Cap Equity 15% 5% 25% Domestic Small-Cap Equity 25% 5% 30% International Equity 20% 10% 30% The Company has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of the Company's members and the Company's Investment Committee. The various investment managers used by the trust operate within the general operating objectives as established in the investment policy and within the specific guidelines established for each investment manager's respective portfolio. The portfolio is rebalanced at least on an annual basis to bring the asset allocations of various managers in line with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price movements in the financial markets which may cause the trust's exposure to any asset class to exceed or fall below the established allowable guidelines. To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however, expected that performance goals will be met over a full market cycle, normally defined as a three to five year period. Analysis of performance is within the context of the prevailing investment environment and the advisors' investment style. The goal of the trust is to provide a rate of return consistently from three percent to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis over a typical market cycle of no less than three years and no more than five years. Each investment manager is expected to outperform its respective benchmark. Below is a list of each asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against: Asset Class Comparative Benchmark(s) Active Duration Fixed Income Bloomberg Barclays Aggregate Long Duration Fixed Income Duration blended Barclays Long Government/Credit & Barclays Universal Equity Index Standard & Poor's 500 Index Mid-Cap Equity Russell Midcap Index Russell Midcap Value Index Small-Cap Equity Russell 2000 Index Russell 2000 Value Index International Equity Morgan Stanley Capital Investment ACWI ex-US The fixed income managers are expected to use discretion over the asset mix of the trust assets in its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S. government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed income portfolio as measured by market value. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody's Investors Services, Standard & Poor's Ratings Services or Fitch Ratings. The portfolio may invest up to 10 percent of the portfolio's market value in convertible bonds as long as the securities purchased meet the quality guidelines. A portfolio may invest up to 15 percent of the portfolio's market value in private placement, including 144A securities with or without registration rights and allow for futures to be traded in the portfolio. The purchase of any of the Company's equity, debt or other securities is prohibited. The domestic value equity managers focus on stocks that the manager believes are undervalued in price and earn an average or less than average return on assets, and often pays out higher than average dividend payments. The domestic growth equity manager will invest primarily in growth companies which consistently experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into existing business. The domestic mid-cap equity portfolio manager focuses on companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell Midcap Index, small dividend yield, return on equity at or near the Russell Midcap Index and an earnings per share growth rate at or near the Russell Midcap Index. The domestic small-cap equity manager will purchase shares of companies with market capitalizations lower than the average company traded on the public exchanges with the following characteristics: price/earnings ratio at or near the Russell 2000, small dividend yield, return on equity at or near the Russell 2000 and an earnings per share growth rate at or near the Russell 2000. The international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across the global equity markets. The manager is required to operate under certain restrictions including: regional constraints, diversification requirements and percentage of U.S. securities. The Morgan Stanley Capital International All Country World ex-US Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-US Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the United States. All of the equities which are purchased for the international portfolio are thoroughly researched. All securities are freely traded on a recognized stock exchange and there are no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares). For all domestic equity investment managers, no more than five percent can be invested in any one stock at the time of purchase and no more than 10 percent after accounting for price appreciation. Options or financial futures may not be purchased unless prior approval of the Company's Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of the Company's equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager's organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock.
Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]	401(k) Plan The Company provides a 401(k) Plan. Each regular full-time employee of the Company or a participating affiliate is eligible to participate in the 401(k) Plan immediately. All other employees of the Company or a participating affiliate are eligible to become participants in the 401(k) Plan after completing one year of service as defined in the 401(k) Plan. Participants may contribute each pay period any whole percentage between two percent and 19 percent of their compensation, as defined in the 401(k) Plan, for that pay period. Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as "Catch-Up Contributions," subject to certain limitations of the Code. Participants may designate, at their discretion, all or any portion of their contributions as: (i) a before-tax contribution under Section 401(k) of the Code subject to the limitations thereof; (ii) a contribution made on a non Roth after-tax basis; or (iii) a Roth contribution. The 401(k) Plan also includes an eligible automatic contribution arrangement and provides for a qualified default investment alternative consistent with the U.S. Department of Labor regulations. Participants may elect, in accordance with the 401(k) Plan procedures, to have his or her future salary deferral rate to be automatically increased annually on a date and in an amount as specified by the participant in such election. For employees hired or rehired on or after December 1, 2009, the Company contributes to the 401(k) Plan, on behalf of each participant, 200 percent of the participant's contributions up to five percent of compensation. No Company contributions are made with respect to a participant's Catch-Up Contributions, rollover contributions, or with respect to a participant's contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Once made, the Company's contribution may be directed to any available investment option in the 401(k) Plan. The Company match contributions vest over a three -year period. After two years of service, participants become 20 percent vested in their Company contribution account and become fully vested on completing three years of service. In addition, participants fully vest when they are eligible for normal or early retirement under the Pension Plan, in the event of their termination due to death or permanent disability or upon attainment of age 65 while employed by the Company or its affiliates. The Company contributed $11.9 million , $11.6 million and $15.2 million in 2016 , 2015 and 2014 , respectively, to the 401(k) Plan. Deferred Compensation Plan The Company provides a nonqualified deferred compensation plan which is intended to be an unfunded plan. The plan's primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of the Company and to supplement such employees' 401(k) Plan contributions as well as offering this plan to be competitive in the marketplace. Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of annual bonus awards or (ii) eligible employees may elect a deferral percentage of base salary and bonus awards based on the deferral percentage elected for a year under the 401(k) Plan with such deferrals to start when maximum deferrals to the qualified 401(k) Plan have been made because of limitations in that plan. Eligible directors who enroll in the plan may elect to defer up to a maximum of 100 percent of directors' meeting fees and annual retainers. The Company matches employee (but not non-employee director) deferrals to make up for any match lost in the 401(k) Plan because of deferrals to the deferred compensation plan, and to allow for a match that would have been made under the 401(k) Plan on that portion of either the first six percent of total compensation or the first five percent of total compensation, depending on prior participant elections, deferred that exceeds the limits allowed in the 401(k) Plan. Matching credits vest based on years of service, with full vesting after three years or, if earlier, on retirement, disability, death, a change in control of the Company or termination of the plan. Deferrals, plus any Company match, are credited to a recordkeeping account in the participant's name. Earnings on the deferrals are indexed to the assumed investment funds selected by the participant. In 2016 , those investment options included a Company Common Stock fund, whose value was determined based on the stock price of the Company's Common Stock. The Company accounts for the contributions related to the Company's executive officers in this plan as Accrued Benefit Obligations and the Company accounts for the contributions related to the Company's directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in the Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income and the increase in the liability under the plan is accounted for as Other Expense in the Consolidated Statements of Income.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Regulatory Assets and Liabilities [Table Text Block]	The following table is a summary of OG&E's regulatory assets and liabilities at: December 31 (In millions) 2016 2015 Regulatory Assets Current Fuel clause under recoveries $ 51.3 $ — Oklahoma demand program rider under recovery (A) 51.0 36.6 SPP cost tracker under recovery (A) 10.0 4.5 Other (A) 9.5 5.4 Total Current Regulatory Assets $ 121.8 $ 46.5 Non-Current Benefit obligations regulatory asset $ 232.6 $ 242.2 Income taxes recoverable from customers, net 62.3 56.7 Smart Grid 43.2 43.6 Deferred storm expenses 35.7 27.6 Unamortized loss on reacquired debt 13.4 14.8 Other 17.6 17.3 Total Non-Current Regulatory Assets $ 404.8 $ 402.2 Regulatory Liabilities Current Fuel clause over recoveries $ — $ 61.3 Other (B) 12.3 7.5 Total Current Regulatory Liabilities $ 12.3 $ 68.8 Non-Current Accrued removal obligations, net $ 262.8 $ 254.9 Pension tracker 35.5 17.7 Other (C) 1.4 1.0 Total Non-Current Regulatory Liabilities $ 299.7 $ 273.6 (A) Included in Other Current Assets on the Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Consolidated Balance Sheets. (C) Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities.
Components of Benefit Obligation Regulatory Asset [Table Text Block]	The following table is a summary of the components of the benefit obligations regulatory asset at: December 31 (In millions) 2016 2015 Pension Plan and Restoration of Retirement Income Plan Net loss $ 199.9 $ 214.1 Postretirement Benefit Plans Net loss 32.7 34.2 Prior service cost — (6.1 ) Total $ 232.6 $ 242.2
Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]	The following amounts in the benefit obligations regulatory asset at December 31, 2016 are expected to be recognized as components of net periodic benefit cost in 2017 : (In millions) Pension Plan and Restoration of Retirement Income Plan Net loss $ 12.4 Postretirement Benefit Plans Net loss 2.3 Total $ 14.7
Schedule of Jointly Owned Utility Plants [Table Text Block]	The tables below present OG&E's ownership interest in the jointly-owned McClain Plant and the jointly-owned Redbud Plant, and, as disclosed below, only OG&E's ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in these tables. The owners of the remaining interests in the McClain Plant and the Redbud Plant are responsible for providing their own financing of capital expenditures. Also, only OG&E's proportionate interests of any direct expenses of the McClain Plant and the Redbud Plant, such as fuel, maintenance expense and other operating expenses, are included in the applicable financial statement captions in the Consolidated Statements of Income. December 31, 2016 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 234.2 $ 72.3 $ 161.9 Redbud Plant (A)(B) 51 % $ 489.0 $ 121.0 $ 368.0 (A) Construction work in progress was $0.2 million and $1.8 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million . December 31, 2015 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 220.4 $ 62.8 $ 157.6 Redbud Plant (A)(B) 51 % $ 487.5 $ 101.2 $ 386.3 (A) Construction work in progress was $1.6 million and $1.3 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million .
Property, Plant and Equipment [Table Text Block]	The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes at: December 31, 2016 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy (holding company) Property, plant and equipment $ 117.7 $ 103.3 $ 14.4 OGE Energy property, plant and equipment 117.7 103.3 14.4 OG&E Distribution assets 3,896.2 1,221.5 2,674.7 Electric generation assets (A) 4,155.9 1,493.3 2,662.6 Transmission assets (B) 2,548.8 481.3 2,067.5 Intangible plant 85.0 43.9 41.1 Other property and equipment 381.5 145.6 235.9 OG&E property, plant and equipment 11,067.4 3,385.6 7,681.8 Total property, plant and equipment $ 11,185.1 $ 3,488.9 $ 7,696.2 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million . December 31, 2015 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy (holding company) Property, plant and equipment $ 139.0 $ 112.7 $ 26.3 OGE Energy property, plant and equipment 139.0 112.7 26.3 OG&E Distribution assets 3,728.8 1,152.8 2,576.0 Electric generation assets (A) 3,837.4 1,407.0 2,430.4 Transmission assets (B) 2,454.2 440.7 2,013.5 Intangible plant 81.0 38.0 43.0 Other property and equipment 356.4 123.2 233.2 OG&E property, plant and equipment 10,457.8 3,161.7 7,296.1 Total property, plant and equipment $ 10,596.8 $ 3,274.4 $ 7,322.4 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.5 million .
Schedule of Unamortized Computer Software Costs [Table Text Block]	The following table summarizes the Company's unamortized computer software costs. December 31 (In millions) 2016 2015 OGE Energy (holding company) $ 1.0 $ 2.4 OG&E 36.5 34.3 Total $ 37.5 $ 36.7
Schedule of Computer Software Costs, Amortization [Table Text Block]	The following table summarizes the Company's amortization expense for computer software costs. Year ended December 31 (In millions) 2016 2015 2014 OGE Energy (holding company) $ 1.4 $ 2.0 $ 4.3 OG&E 8.0 6.9 5.2 Total $ 9.4 $ 8.9 $ 9.5
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2016 and 2015 . (In millions) 2016 2015 Balance at January 1 $ 63.3 $ 58.6 Accretion expense 2.8 2.6 Revisions in estimated cash flows (A) 3.6 1.6 Additions — 0.9 Liabilities settled (0.1 ) (0.4 ) Balance at December 31 $ 69.6 $ 63.3 (A) Assumptions changed related to the estimated cost of asbestos abatement.
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following tables summarize changes in the components of accumulated other comprehensive loss attributable to OGE Energy during 2015 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 (loss) Prior service cost Net income (loss) Prior service cost Total Balance at December 31, 2014 $ (36.8 ) $ 0.1 $ (8.0 ) $ 3.3 $ (41.4 ) Other comprehensive income (loss) before reclassifications (9.5 ) — 9.3 — (0.2 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.5 — 1.2 (1.8 ) 1.9 Settlement cost 4.6 — — — 4.6 Net current period other comprehensive income (loss) (2.4 ) — 10.5 (1.8 ) 6.3 Balance at December 31, 2015 (39.2 ) 0.1 2.5 1.5 (35.1 ) Other comprehensive income (loss) before reclassifications (0.7 ) — 0.2 — (0.5 ) Amounts reclassified from accumulated other comprehensive income (loss) 2.8 — — (1.5 ) 1.3 Settlement cost 5.0 — — — 5.0 Net current period other comprehensive income (loss) 7.1 — 0.2 (1.5 ) 5.8 Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 )
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the years ended December 31, 2016 and 2015 . Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Statement Where Net Income is Presented Year Ended December 31, (In millions) 2016 2015 Amortization of defined benefit pension and restoration of retirement income plan items Actuarial losses $ (4.5 ) $ (4.7 ) (A) Settlement (8.2 ) (7.5 ) (A) (12.7 ) (12.2 ) Total before tax (4.9 ) (5.1 ) Tax benefit $ (7.8 ) $ (7.1 ) Net of tax Amortization of postretirement benefit plan items Actuarial losses $ — $ (2.0 ) (A) Prior service cost 2.5 2.9 (A) 2.5 0.9 Total before tax 1.0 0.3 Tax expense $ 1.5 $ 0.6 Net of tax Total reclassifications for the period $ (6.3 ) $ (6.5 ) Net of tax (A) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	The amounts in accumulated other comprehensive loss at December 31, 2016 that are expected to be recognized into earnings in 2017 are as follows: (In millions) Pension Plan and Restoration of Retirement Income Plan Net loss $ (3.9 ) Postretirement Benefit Plans Net loss — Prior service cost — Total, net of tax $ (3.9 )

Investment in Unconsolidated 29

Investment in Unconsolidated Affiliate and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2015 to December 31, 2016 . (In millions) Basis difference as of December 31, 2015 $ 783.5 Dilution and impairments associated with OGE Energy’s basis difference (11.3 ) Amortization of basis difference (11.6 ) Elimination of Enable fair value step up (16.9 ) Basis difference as of December 31, 2016 $ 743.7
Schedule of Related Party Transactions [Table Text Block]	The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2016 , 2015 and 2014 . Year Ended December 31, (In millions) 2016 2015 2014 Operating Revenues: Electricity to power electric compression assets $ 11.5 $ 13.8 $ 13.3 Cost of Sales: Natural gas transportation services $ 35.0 $ 35.0 $ 34.9 Natural gas storage services — — 4.4 Natural gas purchases/(sales) 11.2 7.6 8.7
Summarized Balance Sheet Financial Information, Equity Method Investment [Table Text Block]	Summarized unaudited financial information for 100 percent of Enable is presented below as of December 31, 2016 and 2015 and for the years ended December 31, 2016 , 2015 and 2014 . Balance Sheet December 31, (In millions) 2016 2015 Current assets $ 396 $ 381 Non-current assets 10,816 10,845 Current liabilities 362 615 Non-current liabilities 3,056 3,080
Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]	Income Statement Year Ended December 31, (In millions) 2016 2015 2014 Operating revenues $ 2,272 $ 2,418 $ 3,367 Cost of natural gas and natural gas liquids 1,017 1,097 1,914 Operating income (loss) 385 (712 ) 586 Net income (loss) 290 (752 ) 530
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]	The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for the years ended December 31, 2016 and 2015 . Year Ended December 31, Reconciliation of Equity in Earnings (Loss) of Unconsolidated Affiliates 2016 2015 (In millions) Enable net income (loss) $ 289.5 $ (752.0 ) Distributions senior to limited partners (9.1 ) — Differences due to timing of OGE Energy and Enable accounting close (12.1 ) 12.1 Enable net income (loss) used to calculate OGE Energy's equity in earnings $ 268.3 $ (739.9 ) OGE Energy’s percent ownership at year end 25.7 % 26.3 % OGE Energy’s portion of Enable net income (loss) $ 70.7 $ (194.4 ) Impairments recognized by Enable associated with OGE Energy’s basis differences 2.6 178.4 OGE Energy's share of Enable net income (loss) 73.3 (16.0 ) Amortization of basis difference 11.6 13.5 Elimination of Enable fair value step up 16.9 18.0 Equity in earnings of unconsolidated affiliates $ 101.8 $ 15.5

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value, by Balance Sheet Grouping [Table Text Block]	The following table summarizes the fair value and carrying amount of the Company's financial instruments at December 31, 2016 and 2015 . 2016 2015 December 31 (In millions) Carrying Amount Fair Carrying Amount Fair Long-Term Debt (including Long-Term Debt due within one year) Senior Notes $ 2,385.5 $ 2,657.2 $ 2,493.9 $ 2,754.6 OG&E Industrial Authority Bonds 135.4 135.4 135.4 135.4 Tinker Debt 9.9 11.3 10.0 9.2 OGE Energy Senior Notes 99.7 99.9 99.5 99.9

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Stock-Based Compensation [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]	The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the year s ended December 31, 2016 , 2015 and 2014 related to the Company's performance units and restricted stock . Year ended December 31 (In millions) 2016 2015 2014 Performance units Total shareholder return $ 4.5 $ 7.6 $ 8.3 Earnings per share — 0.7 3.7 Total performance units 4.5 8.3 12.0 Restricted stock 0.1 0.1 — Total compensation expense 4.6 8.4 12.0 Less: Amount paid by unconsolidated affiliates — 0.5 3.6 Net compensation expense $ 4.6 $ 7.9 $ 8.4 Income tax benefit $ 1.8 $ 3.1 $ 3.3
Performance Units Total Shareholder Return Valuation Assumptions [Table Text Block]	The number of performance units granted based on total shareholder return and the assumptions used to calculate the grant date fair value of the performance units based on total shareholder return are shown in the following table. 2016 2015 2014 Number of units granted 284,211 264,454 219,106 Fair value of units granted $ 20.97 $ 31.02 $ 34.80 Expected dividend yield 3.5 % 2.6 % 2.5 % Expected price volatility 19.8 % 16.9 % 20.0 % Risk-free interest rate 0.88 % 0.91 % 0.67 % Expected life of units (in years) 2.84 2.85 2.86
Performance Units Earnings Per Share Valuation Assumptions [Table Text Block]	The number of performance units granted based on earnings per share and the grant date fair value are shown in the following table. 2016 2015 2014 Number of units granted 94,735 88,156 73,037 Fair value of units granted $ 26.64 $ 33.99 $ 34.81
Restricted Stock Valuation Assumptions [Table Text Block]	The number of shares of restricted stock granted and the grant date fair value are shown in the following table. 2016 2015 2014 Shares of restricted stock granted 1,881 958 7,037 Fair value of restricted stock granted $ 29.27 $ 26.11 $ 35.71
Schedule of Share-based Compensation, Activity [Table Text Block]	A summary of the activity for the Company's performance units and restricted stock at December 31, 2016 and changes in 2016 are shown in the following table. Performance Units Total Shareholder Return Earnings Per Share Restricted Stock (Dollars in millions) Number Aggregate Intrinsic Value Number Aggregate Intrinsic Value Number Aggregate Intrinsic Value Units/Shares Outstanding at 12/31/15 724,058 241,470 7,623 Granted 284,211 (A) 94,735 (A) 1,881 Converted (327,988 ) (B) $ — (109,445 ) (B) $ — N/A Vested N/A N/A (4,324 ) $ 0.1 Forfeited (16,236 ) (5,410 ) (268 ) Units/Shares Outstanding at 12/31/16 664,045 $ 17.3 221,350 $ 1.9 4,912 $ 0.2 Units/Shares Fully Vested at 12/31/16 185,214 $ — 61,742 $ — (A) For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. (B) These amounts represent performance units that vested at December 31, 2015 which were settled in February 2016.
Schedule of Nonvested Share Activity [Table Text Block]	A summary of the activity for the Company's non-vested performance units and restricted stock at December 31, 2016 and changes in 2016 are shown in the following table. Performance Units Total Shareholder Return Earnings Per Share Restricted Stock Number Weighted-Average Number Weighted-Average Number Weighted-Average Units/Shares Non-Vested at 12/31/15 396,943 $ 32.83 132,316 $ 34.30 7,623 $ 29.68 Granted 284,211 (A) $ 20.97 94,735 (A) $ 26.64 1,881 $ 29.27 Converted (873 ) (B) $ 33.01 (291 ) (B) $ 33.01 N/A N/A Vested (185,214 ) $ 34.82 (61,742 ) $ 34.83 (4,324 ) $ 32.98 Forfeited (16,236 ) $ 28.89 (5,410 ) $ 31.95 (268 ) $ 37.31 Units/Shares Non-Vested at 12/31/16 478,831 $ 25.16 159,608 $ 29.71 4,912 $ 31.29 Units/Shares Expected to Vest 476,920 (C) 158,975 (C) 4,912 (A) For performance units, this represents the target number of performance units granted. Actual number of performance units earned, if any, is dependent upon performance and may range from zero percent to 200 percent of the target. (B) Units paid out under terms of plan due to the death of a participant. (C) The intrinsic value of the performance units based on total shareholder return and earnings per share is $15.3 million and $5.1 million , respectively.
Fair Value of Vested Performance Units and Restricted Stock [Table Text Block]	A summary of the Company's fair value for its vested performance units and restricted stock is shown in the following table. Year ended December 31 (In millions) 2016 2015 2014 Performance units Total shareholder return $ 6.4 $ 8.5 $ 9.5 Earnings per share — — 3.8 Restricted stock 0.1 0.2 0.2
Schedule of Unrecognized Compensation Cost, Nonvested Awards [Table Text Block]	A summary of the Company's unrecognized compensation cost for its non-vested performance units and restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. December 31, 2016 Unrecognized Compensation Cost (in millions) Weighted Average to be Recognized (in years) Performance units Total shareholder return $ 5.8 1.59 Earnings per share 2.3 1.63 Total performance units 8.1 Restricted stock 0.1 1.55 Total $ 8.2

Supplemental Cash Flow Inform32

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	The following table discloses information about investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments. Also disclosed in the table is cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds. Year ended December 31 (In millions) 2016 2015 2014 NON-CASH INVESTING AND FINANCING ACTIVITIES Power plant long-term service agreement $ 39.5 $ 2.3 $ — SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the period for Interest (net of interest capitalized) (A) $ 141.9 $ 145.4 $ 150.8 Income taxes (net of income tax refunds) (5.9 ) (3.4 ) 0.2 (A) Net of interest capitalized of $7.5 million , $4.2 million and $2.4 million in 2016 , 2015 and 2014 , respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The items comprising income tax expense are as follows: Year ended December 31 (In millions) 2016 2015 2014 Provision (Benefit) for Current Income Taxes Federal $ — $ — $ — State (5.7 ) (5.2 ) (4.5 ) Total Provision (Benefit) for Current Income Taxes (5.7 ) (5.2 ) (4.5 ) Provision for Deferred Income Taxes, net Federal 126.0 98.8 160.0 State 28.0 4.5 18.2 Total Provision for Deferred Income Taxes, net 154.0 103.3 178.2 Deferred Federal Investment Tax Credits, net (0.2 ) (0.7 ) (0.9 ) Total Income Tax Expense $ 148.1 $ 97.4 $ 172.8
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The following schedule reconciles the statutory tax rates to the effective income tax rate: Year ended December 31 2016 2015 2014 Statutory Federal tax rate 35.0 % 35.0 % 35.0 % Federal renewable energy credit (A) (6.8 ) (8.9 ) (6.7 ) Remeasurement of state deferred tax liabilities 0.9 (0.8 ) 0.4 401(k) dividends (0.6 ) (0.7 ) (0.5 ) Federal investment tax credits, net (0.8 ) (0.2 ) (0.2 ) State income taxes, net of Federal income tax benefit 1.9 0.1 1.2 Uncertain tax positions 0.1 0.7 0.5 Amortization of net unfunded deferred taxes 0.7 0.9 0.6 Other 0.1 0.3 0.1 Effective income tax rate 30.5 % 26.4 % 30.4 % (A) Represents credits associated with the production from OG&E's wind farms.
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	The components of Deferred Income Taxes at December 31, 2016 and 2015 , respectively, were as follows: December 31 (In millions) 2016 2015 Non-Current Deferred Income Tax Liabilities, net Accelerated depreciation and other property related differences $ 2,103.2 $ 2,016.0 Investment in Enable Midstream Partners 657.3 623.4 Regulatory asset 34.4 32.7 Income taxes refundable to customers, net 24.1 22.0 Company Pension Plan 16.5 13.7 Bond redemption-unamortized costs 4.3 4.8 Derivative instruments 2.2 1.5 Federal tax credits (220.6 ) (184.4 ) State tax credits (112.2 ) (106.7 ) Postretirement medical and life insurance benefits (48.9 ) (56.2 ) Regulatory liabilities (34.6 ) (46.3 ) Net operating losses (31.7 ) (94.6 ) Asset retirement obligations (24.5 ) (22.5 ) Accrued liabilities (16.1 ) (14.0 ) Other (14.0 ) (6.6 ) Accrued vacation (3.5 ) (3.2 ) Deferred Federal investment tax credits (0.8 ) (0.9 ) Uncollectible accounts (0.6 ) (0.5 ) Non-Current Deferred Income Tax Liabilities, net $ 2,334.5 $ 2,178.2
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	Following is a reconciliation of the Company’s total gross unrecognized tax benefits as of the years ended December 31, 2016 , 2015 , and 2014 . (In millions) 2016 2015 2014 Balance at January 1 $ 20.2 $ 16.1 $ 12.0 Tax positions related to current year: Additions 0.5 4.1 4.1 Balance at December 31 $ 20.7 $ 20.2 $ 16.1
Summary of Tax Credit Carryforwards [Table Text Block]	The following table summarizes these carry forwards: (In millions) Carry Forward Amount Deferred Tax Asset Earliest Expiration Date Net operating losses State operating loss $ 554.7 $ 20.4 2030 Federal operating loss 32.2 11.3 2030 Federal tax credits 220.6 220.6 2029 State tax credits Oklahoma investment tax credits 135.7 88.2 N/A Oklahoma capital investment board credits 7.3 7.3 N/A Oklahoma zero emission tax credits 24.1 16.2 2020 Louisiana inventory credits 0.7 0.5 2019

Common Equity (Tables)

Common Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	Basic and diluted earnings per share for the Company were calculated as follows: (In millions except per share data) 2016 2015 2014 Net income $ 338.2 $ 271.3 $ 395.8 Average Common Shares Outstanding Basic average common shares outstanding 199.7 199.6 199.2 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.2 — 0.7 Diluted average common shares outstanding 199.9 199.6 199.9 Basic Earnings Per Average Common Share $ 1.69 $ 1.36 $ 1.99 Diluted Earnings Per Average Common Share $ 1.69 $ 1.36 $ 1.98 Anti-dilutive shares excluded from earnings per share calculation — — —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows: SERIES DATE DUE AMOUNT (In millions) 0.05% - 0.90% Garfield Industrial Authority, January 1, 2025 $ 47.0 0.07% - 0.83% Muskogee Industrial Authority, January 1, 2025 32.4 0.05% - 0.86% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4

Short-Term Debt and Credit Fa36

Short-Term Debt and Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2016
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	The following table provides information regarding the Company's revolving credit agreements at December 31, 2016 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 750.0 $ 236.2 0.95 % (D) December 13, 2018 (E) OG&E (C) 400.0 1.8 0.95 % (D) December 13, 2018 (E) Total $ 1,150.0 $ 238.0 0.95 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2016 . (B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit. (E) In December 2011, OGE Energy and OG&E entered into unsecured revolving credit agreement s in the aggregate of $1,150.0 million ( $750.0 million for OGE Energy and $400.0 million for OG&E ) which expire in December 2018. OGE Energy and OG&E expect to replace the existing agreements with new revolving credit agreements during 2017, under terms and conditions generally similar to the existing agreements.

Retirement Plans and Postreti37

Retirement Plans and Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Retirement Plans and Postretirement Benefit Plans [Abstract]
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]	The following table presents the status of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans for 2016 and 2015 . These amounts have been recorded in Accrued Benefit Obligations with the offset in Accumulated Other Comprehensive Loss (except OG&E's portion which is recorded as a regulatory asset as discussed in Note 1 ) in the Company's Consolidated Balance Sheets. The amounts in Accumulated Other Comprehensive Loss and those recorded as a regulatory asset represent a net periodic benefit cost to be recognized in the Consolidated Statements of Income in future periods. The benefit obligation for the Company's Pension Plan and the Restoration of Retirement Income Plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated postretirement benefit obligation. The accumulated postretirement benefit obligation for the Company's Pension Plan and Restoration of Retirement Income Plan differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2016 was $608.0 million and $6.1 million , respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2015 was $ 610.9 million and $ 24.6 million , respectively. The details of the funded status of the Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans and the amounts included in the Consolidated Balance Sheets are as follows: Pension Plan Restoration of Retirement Postretirement December 31 (In millions) 2016 2015 2016 2015 2016 2015 Change in Benefit Obligation Beginning obligations $ 680.0 $ 725.0 $ 25.1 $ 19.7 $ 225.3 $ 280.9 Service cost 15.8 16.1 0.3 1.3 0.8 1.5 Interest cost 25.5 26.1 0.4 0.7 9.5 10.3 Plan settlements — (60.7 ) (20.6 ) — — — Participants' contributions — — — — 3.6 3.4 Actuarial (gains) losses 4.7 (11.3 ) 1.8 4.0 (7.6 ) (55.1 ) Benefits paid (53.8 ) (15.2 ) — (0.6 ) (15.7 ) (15.7 ) Ending obligations $ 672.2 $ 680.0 $ 7.0 $ 25.1 $ 215.9 $ 225.3 Change in Plans' Assets Beginning fair value $ 581.7 $ 679.8 $ — $ — $ 55.3 $ 59.6 Actual return on plans' assets 48.0 (22.2 ) — — 2.0 (0.5 ) Employer contributions 20.0 — 20.6 0.6 7.9 8.5 Plan settlements — (60.7 ) (20.6 ) — — — Participants' contributions — — — — 3.6 3.4 Benefits paid (53.8 ) (15.2 ) — (0.6 ) (15.7 ) (15.7 ) Ending fair value $ 595.9 $ 581.7 $ — $ — $ 53.1 $ 55.3 Funded status at end of year $ (76.3 ) $ (98.3 ) $ (7.0 ) $ (25.1 ) $ (162.8 ) $ (170.0 )
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	Net Periodic Benefit Cost Pension Plan Restoration of Retirement Postretirement Benefit Plans Year ended December 31 (In millions) 2016 2015 2014 2016 2015 2014 2016 2015 2014 Service cost $ 15.8 $ 16.1 $ 15.3 $ 0.3 $ 1.3 $ 1.1 $ 0.8 $ 1.5 $ 3.1 Interest cost 25.5 26.1 28.1 0.4 0.7 0.6 9.5 10.3 11.4 Expected return on plan assets (41.5 ) (46.0 ) (45.3 ) — — — (2.3 ) (2.4 ) (2.4 ) Amortization of net loss 16.5 18.0 14.3 0.7 0.6 0.2 2.6 13.9 12.3 Amortization of unrecognized prior service cost (A) (0.1 ) 0.4 1.7 0.1 0.1 0.2 (8.8 ) (16.5 ) (16.5 ) Curtailment — — (0.2 ) — — — — — — Settlement — 21.7 — 8.6 — — — — — Total net periodic benefit cost 16.2 36.3 13.9 10.1 2.7 2.1 1.8 6.8 7.9 Less: Amount paid by unconsolidated affiliates 5.1 4.2 3.2 0.3 0.1 0.1 0.2 1.3 1.3 Net periodic benefit cost (B) $ 11.1 $ 32.1 $ 10.7 $ 9.8 $ 2.6 $ 2.0 $ 1.6 $ 5.5 $ 6.6 (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 $22.5 million , $40.2 million and $19.3 million of net periodic benefit cost recognized in 2016 , 2015 and 2014 , respectively, OG&E recognized the following: • a change in pension expense in 2016 , 2015 and 2014 of $9.9 million , $(3.1) million and $11.2 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 asset or liability (see Note 1); • an increase in postretirement medical expense in 2016 , 2015 and 2014 of $7.9 million , $5.8 million and $5.2 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and • a deferral of pension expense in 2016 and 2015 of $0.1 million and $1.9 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.6 million and $21.7 million , respectively.
Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]	(In millions) 2016 2015 2014 Capitalized portion of net periodic pension benefit cost $ 4.0 $ 5.0 $ 3.4 Capitalized portion of net periodic postretirement benefit cost 0.8 1.9 2.0
Schedule of Assumptions Used [Table Text Block]	Rate Assumptions Pension Plan and Postretirement Year ended December 31 2016 2015 2014 2016 2015 2014 Discount rate 4.00 % 4.00 % 3.80 % 4.20 % 4.25 % 3.80 % Rate of return on plans' assets 7.50 % 7.50 % 7.50 % 4.00 % 4.00 % 4.00 % Compensation increases 4.20 % 4.20 % 4.20 % N/A N/A N/A Assumed health care cost trend: Initial trend N/A N/A N/A 6.75 % 6.10 % 7.85 % Ultimate trend rate N/A N/A N/A 4.50 % 4.50 % 4.48 % Ultimate trend year N/A N/A N/A 2026 2026 2028 N/A - not applicable
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]	A one-percentage point change in the assumed health care cost trend rate would have the following effects: ONE-PERCENTAGE POINT INCREASE Year ended December 31 (In millions) 2016 2015 2014 Effect on aggregate of the service and interest cost components $ — $ — $ — Effect on accumulated postretirement benefit obligations 0.2 0.2 0.1 ONE-PERCENTAGE POINT DECREASE Year ended December 31 (In millions) 2016 2015 2014 Effect on aggregate of the service and interest cost components $ — $ 0.1 $ 0.1 Effect on accumulated postretirement benefit obligations 0.7 0.7 0.7
Projected Benefit Obligation Funded Status Thresholds [Table Text Block]	The Pension Plan assets are held in a trust which follows an investment policy and strategy designed to reduce the funded status volatility of the Plan by utilizing liability driven investing. The purpose of liability driven investing is to structure the asset portfolio to more closely resemble the pension liability and thereby more effectively hedge against changes in the liability. The investment policy follows a glide path approach that shifts a higher portfolio weighting to fixed income as the Plan's funded status increases. The table below sets forth the targeted fixed income and equity allocations at different funded status levels. Projected Benefit Obligation Funded Status Thresholds <90% 95% 100% 105% 110% 115% 120% Fixed income 50% 58% 65% 73% 80% 85% 90% Equity 50% 42% 35% 27% 20% 15% 10% Total 100% 100% 100% 100% 100% 100% 100%
Pension Plan Equity Asset Allocation Table [Table Text Block]	Within the portfolio's overall allocation to equities, the funds are allocated according to the guidelines in the table below. Asset Class Target Allocation Minimum Maximum Domestic Large Cap Equity 40% 35% 60% Domestic Mid-Cap Equity 15% 5% 25% Domestic Small-Cap Equity 25% 5% 30% International Equity 20% 10% 30%
Schedule of Allocation of Plan Assets [Table Text Block]	The following tables summarize the postretirement benefit plans investments that are measured at fair value on a recurring basis at December 31, 2016 and 2015 . There were no Level 2 investments held by the postretirement benefit plans at December 31, 2016 and 2015 . (In millions) December 31, 2016 Level 1 Level 3 Group retiree medical insurance contract (A) $ 44.7 $ — $ 44.7 Mutual funds investment U.S. equity investments 8.1 8.1 — Cash 0.3 0.3 — Total Plan investments $ 53.1 $ 8.4 $ 44.7 (In millions) December 31, 2015 Level 1 Level 3 Group retiree medical insurance contract (A) $ 46.8 $ — $ 46.8 Mutual funds investment U.S. equity investments 7.8 7.8 — Money market funds investment 0.7 0.7 — Total Plan investments $ 55.3 $ 8.5 $ 46.8 (A) This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2016 and 2015 . There were no Level 3 investments held by the Pension Plan at December 31, 2016 and 2015 . (In millions) December 31, 2016 Level 1 Level 2 NAV Common stocks $ 237.1 $ 237.1 $ — $ — U.S. treasury notes and bonds (A) 122.3 122.3 — — Mortgage and asset-backed securities 59.2 — 59.2 — Corporate fixed income and other securities 137.6 — 137.6 — Commingled fund (B) 23.8 — — 23.8 Foreign government bonds 5.2 — 5.2 — U.S. municipal bonds 1.9 — 1.9 — Money market fund 2.2 — — 2.2 Mutual fund 9.0 9.0 — — Futures U.S. Treasury futures (receivable) 10.7 — 10.7 — U.S. Treasury futures (payable) (2.3 ) — (2.3 ) — Cash collateral 0.3 0.3 — — Forward contracts Receivable (foreign currency) 0.2 — 0.2 — Total Plan investments $ 607.2 $ 368.7 $ 212.5 $ 26.0 Receivable from broker for securities sold — Interest and dividends receivable 3.0 Payable to broker for securities purchased (14.3 ) Total Plan assets $ 595.9 (In millions) December 31, 2015 Level 1 Level 2 NAV Common stocks $ 208.2 $ 208.2 $ — $ — U.S. treasury notes and bonds (A) 158.9 158.9 — — Mortgage-backed securities 14.5 — 14.5 — Corporate fixed income and other securities 140.2 — 140.2 — Commingled fund (B) 24.4 — — 24.4 Foreign government bonds 5.6 — 5.6 — U.S. municipal bonds 4.9 — 4.9 — Interest-bearing cash 0.4 0.4 — — Money market fund 11.7 — — 11.7 Index fund 1.8 1.8 — — Mutual fund 24.3 24.3 — — Preferred stocks 0.3 0.3 — — Futures U.S. Treasury futures (receivable) 17.6 — 17.6 — U.S. Treasury futures (payable) (12.4 ) — (12.4 ) — Forward contracts Receivable (foreign currency) 0.1 — 0.1 — Payable (foreign currency) (0.1 ) — (0.1 ) — Total Plan investments $ 600.4 $ 393.9 $ 170.4 $ 36.1 Receivable from broker for securities sold — Interest and dividends receivable 3.5 Payable to broker for securities purchased (22.2 ) Total Plan assets $ 581.7 (A) This category represents U.S. treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher. (B) This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]	The following table summarizes the postretirement benefit plans investments that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3). Year ended December 31 (In millions) 2016 Group retiree medical insurance contract Beginning balance $ 46.8 Interest income 0.9 Dividend income 0.6 Net unrealized gains related to instruments held at the reporting date 0.2 Realized losses (0.1 ) Claims paid (3.7 ) Ending balance $ 44.7
Schedule of Expected Benefit Payments [Table Text Block]	The Medicare Prescription Drug, Improvement and Modernization Act of 2003 expanded coverage for prescription drugs. The following table summarizes the gross benefit payments the Company expects to pay related to its postretirement benefit plans, including prescription drug benefits . (In millions) Gross Projected 2017 $ 14.0 2018 14.1 2019 14.1 2020 14.1 2021 14.1 After 2021 69.1 The following table summarizes the benefit payments the Company expects to pay related to OGE Energy's Pension Plan and Restoration of Retirement Income Plan. These expected benefits are based on the same assumptions used to measure the Company's benefit obligation at the end of the year and include benefits attributable to estimated future employee service. (In millions) Projected Benefit Payments 2017 $ 48.7 2018 48.7 2019 51.9 2020 54.6 2021 55.7 After 2021 290.1

Report of Business Segments (Ta

Report of Business Segments (Tables)	12 Months Ended
	Dec. 31, 2016
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 for the years ended December 31, 2016 , 2015 and 2014 . 2016 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 2,259.2 $ — $ — $ — $ 2,259.2 Cost of sales 880.1 — — — 880.1 Other operation and maintenance 469.8 7.7 (11.9 ) — 465.6 Depreciation and amortization 316.4 — 6.2 — 322.6 Taxes other than income 84.0 — 3.6 — 87.6 Operating income (loss) 508.9 (7.7 ) 2.1 — 503.3 Equity in earnings of unconsolidated affiliates — 101.8 — — 101.8 Other income (expense) 27.7 0.1 (4.3 ) (0.2 ) 23.3 Interest expense 138.1 — 4.2 (0.2 ) 142.1 Income tax expense (benefit) 114.4 40.5 (6.8 ) — 148.1 Net income $ 284.1 $ 53.7 $ 0.4 $ — $ 338.2 Investment in unconsolidated affiliates $ — $ 1,158.6 $ — $ — $ 1,158.6 Total assets $ 8,669.4 $ 1,521.6 $ 89.0 $ (340.4 ) $ 9,939.6 Capital expenditures $ 660.1 $ — $ — $ — $ 660.1 2015 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 2,196.9 $ — $ — $ — $ 2,196.9 Cost of sales 865.0 — — — 865.0 Other operation and maintenance 444.5 7.5 (0.4 ) — 451.6 Depreciation and amortization 299.9 — 8.0 — 307.9 Taxes other than income 87.1 — 4.1 — 91.2 Operating income (loss) 500.4 (7.5 ) (11.7 ) — 481.2 Equity in earnings of unconsolidated affiliates (A) — 15.5 — — 15.5 Other income (expense) 20.0 0.4 0.9 (0.3 ) 21.0 Interest expense 146.7 — 2.6 (0.3 ) 149.0 Income tax expense (benefit) 104.8 (1.0 ) (6.4 ) — 97.4 Net income $ 268.9 $ 9.4 $ (7.0 ) $ — $ 271.3 Investment in unconsolidated affiliates $ — $ 1,194.4 $ — $ — $ 1,194.4 Total assets $ 8,525.5 $ 1,439.5 $ 174.6 $ (559.0 ) $ 9,580.6 Capital expenditures $ 551.6 $ — $ (3.8 ) $ — $ 547.8 (A) In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment. 2014 Electric Utility Natural Gas Midstream Operations Other Operations Eliminations Total (In millions) Operating revenues $ 2,453.1 $ — $ — $ — $ 2,453.1 Cost of sales 1,106.6 — — — 1,106.6 Other operation and maintenance 453.2 1.2 (14.8 ) — 439.6 Depreciation and amortization 270.8 — 10.6 — 281.4 Taxes other than income 84.5 — 4.2 — 88.7 Operating income (loss) 538.0 (1.2 ) — — 536.8 Equity in earnings of unconsolidated affiliates — 172.6 — — 172.6 Other income (expense) 7.1 — 0.7 (0.2 ) 7.6 Interest expense 141.5 — 7.1 (0.2 ) 148.4 Income tax expense (benefit) 111.6 69.1 (7.9 ) — 172.8 Net income 292.0 102.3 1.5 — 395.8 Investment in unconsolidated affiliates $ — $ 1,318.2 $ — $ — $ 1,318.2 Total assets $ 8,248.9 $ 1,461.2 $ 128.6 $ (328.8 ) $ 9,509.9 Capital expenditures $ 565.4 $ — $ 10.8 $ (6.9 ) $ 569.3

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Future minimum payments for noncancellable operating leases are as follows: Year ended December 31 (In millions) 2017 2018 2019 2020 2021 After 2021 Total Operating lease obligations Railcars $ 2.7 $ 1.7 $ 21.0 $ — $ — $ — $ 25.4 Wind farm land leases 2.5 2.5 2.5 2.9 2.9 43.5 56.8 Noncancellable operating lease 0.8 0.7 — — — — 1.5 Total operating lease obligations $ 6.0 $ 4.9 $ 23.5 $ 2.9 $ 2.9 $ 43.5 $ 83.7
Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]	The Company's other future purchase obligations and commitments estimated for the next five years are as follows: (In millions) 2017 2018 2019 2020 2021 Total Other purchase obligations and commitments Cogeneration capacity and fixed operation and maintenance payments $ 77.1 $ 73.9 $ 66.5 $ 54.7 $ 51.0 $ 323.2 Expected cogeneration energy payments 37.7 37.5 38.9 40.7 44.4 199.2 Minimum fuel purchase commitments 236.2 49.3 36.2 24.6 24.6 370.9 Expected wind purchase commitments 59.0 57.9 56.6 57.1 57.5 288.1 Long-term service agreement commitments 2.2 28.4 22.2 2.4 2.4 57.6 Mustang Modernization expenditures 130.4 21.9 — — — 152.3 Environmental compliance plan expenditures 169.2 63.0 8.9 0.2 — 241.3 Total other purchase obligations and commitments $ 711.8 $ 331.9 $ 229.3 $ 179.7 $ 179.9 $ 1,632.6
Schedule of Wind Power Purchases [Table Text Block]	The following table summarizes OG&E's wind power purchases for the years ended December 31, 2016 , 2015 and 2014 . Year ended December 31 (In millions) 2016 2015 2014 CPV Keenan $ 29.2 $ 26.7 $ 28.1 Edison Mission Energy 21.1 19.7 21.3 FPL Energy 3.4 3.2 3.6 NextEra Energy 7.3 7.0 7.8 Total wind power purchased $ 61.0 $ 56.6 $ 60.8

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information [Table Text Block]	In the Company's opinion, the following quarterly financial data includes all adjustments, consisting of normal recurring adjustments, necessary to fairly present such amounts. Summarized consolidated quarterly unaudited financial data is as follows: Quarter ended ( In millions, except per share data) March 31 June 30 September 30 December 31 Total Operating revenues 2016 $ 433.1 $ 551.4 $ 743.9 $ 530.8 $ 2,259.2 2015 $ 480.1 $ 549.9 $ 719.8 $ 447.1 $ 2,196.9 Operating income 2016 $ 37.9 $ 125.9 $ 257.3 $ 82.2 $ 503.3 2015 $ 56.4 $ 127.2 $ 250.8 $ 46.8 $ 481.2 Net income 2016 $ 25.2 $ 71.5 $ 183.6 $ 57.9 $ 338.2 2015 $ 43.2 $ 87.5 $ 111.2 $ 29.4 $ 271.3 Basic earnings per average common share (A) 2016 $ 0.13 $ 0.35 $ 0.92 $ 0.29 $ 1.69 2015 $ 0.22 $ 0.44 $ 0.55 $ 0.15 $ 1.36 Diluted earnings per average common share (A) 2016 $ 0.13 $ 0.35 $ 0.92 $ 0.29 $ 1.69 2015 $ 0.22 $ 0.44 $ 0.55 $ 0.15 $ 1.36 (A) Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

Schedule II (Tables)

Schedule II (Tables)	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
Schedule II Valuation and Qualifying Accounts [Table Text Block]	SCHEDULE II - Valuation and Qualifying Accounts Additions Description Balance at Beginning of Period Charged to Costs and Expenses Deductions (A) Balance at End of Period (In millions) Balance at December 31, 2014 Reserve for Uncollectible Accounts $ 1.9 $ 2.3 $ 2.6 $ 1.6 Balance at December 31, 2015 Reserve for Uncollectible Accounts $ 1.6 $ 2.4 $ 2.6 $ 1.4 Balance at December 31, 2016 Reserve for Uncollectible Accounts $ 1.4 $ 2.5 $ 2.4 $ 1.5 (A) Uncollectible accounts receivable written off, net of recoveries.

Summary of Significant Accoun42

Summary of Significant Accounting Policies Regulated Operations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2016
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries		$ 0	$ 51.3
Fuel clause over recoveries		61.3	0
Regulatory Assets, Current		46.5	121.8
Regulatory Assets, Noncurrent		402.2	404.8
Regulatory Liability, Current		68.8	12.3
Regulatory Liability, Noncurrent		273.6	299.7
Prior Period Reclassification Adjustment		1
Other Regulatory Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	7.5	12.3
Regulatory Liability, Noncurrent	[2]	1	1.4
Accrued removal obligations [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		254.9	262.8
Pension tracker [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		17.7	35.5
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[3]	36.6	51
SPP cost tracker under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[3]	4.5	10
Other Regulatory Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[3]	5.4	9.5
Regulatory Assets, Noncurrent		17.3	17.6
Benefit obligations regulatory asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		242.2	232.6
Income taxes recoverable from customers, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		56.7	62.3
Smart Grid [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		43.6	43.2
Deferred storm expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		27.6	35.7
Unamortized loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		$ 14.8	$ 13.4
[1]	Included in Other Current Liabilities on the Consolidated Balance Sheets.
[2]	Prior year amount of $1.0 million reclassified from Deferred Other Liabilities to Non-Current Regulatory Liabilities.
[3]	Included in Other Current Assets on the Consolidated Balance Sheets.

Summary of Significant Accoun43

Summary of Significant Accounting Policies Accounting Records (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets, Current	$ 121.8	$ 46.5
Regulatory Assets, Noncurrent	404.8	402.2
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	(3.9)
Deferred Storm and Property Reserve Deficiency, Current	2.7
Smart Grid Project [Member]
Smart Grid Costs to be Recovered	6.9
Benefit Obligations [Member]
Regulatory Assets, Noncurrent	232.6	242.2
Regulatory Asset [Member]
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	14.7
Pension Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Components of Benefit Obligation Regulatory Asset	199.9	214.1
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	12.4
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Components of Benefit Obligation Regulatory Asset	32.7	34.2
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	2.3
Other Postretirement Benefit Plans, Defined Benefit [Member] | Prior Service Cost [Member]
Components of Benefit Obligation Regulatory Asset	$ 0	$ (6.1)

Summary of Significant Accoun44

Summary of Significant Accounting Policies Allowance for Uncollectible Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Allowance for Doubtful Accounts Receivable	$ 1.5	$ 1.4

Summary of Significant Accoun45

Summary of Significant Accounting Policies Fuel Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other	$ 81.8	$ 55.6
Public Utilities, Inventory, Fuel [Member]
Public Utilities, Inventory	82.4	$ 119.3
Other Assets	2.7		$ 11
Other	$ 3

Summary of Significant Accoun46

Summary of Significant Accounting Policies Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 11,185.1		$ 10,596.8
Accumulated Depreciation	3,488.9		3,274.4
Net property, plant and equipment	7,696.2		7,322.4
Capitalized Computer Software, Gross	37.5		36.7
Capitalized Computer Software, Amortization	$ 9.4		$ 8.9		$ 9.5
McClain Plant [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	77.00%	[1]	77.00%	[2]
Property, Plant and Equipment, Gross	$ 234.2	[1]	$ 220.4	[2]
Accumulated Depreciation	72.3	[1]	62.8	[2]
Net property, plant and equipment	161.9	[1]	157.6	[2]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0.2		$ 1.6
Redbud Plant [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	51.00%	[1],[3]	51.00%	[2],[4]
Property, Plant and Equipment, Gross	$ 489	[1],[3]	$ 487.5	[2],[4]
Accumulated Depreciation	121	[1],[3]	101.2	[2],[4]
Net property, plant and equipment	368	[1],[3]	386.3	[2],[4]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1.8		1.3
Amount of Acquisition Adjustments	148.3		148.3
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	45.3		39.8
OGE Energy [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	117.7		139
Accumulated Depreciation	103.3		112.7
Net property, plant and equipment	14.4		26.3
Capitalized Computer Software, Gross	1		2.4
Capitalized Computer Software, Amortization	1.4		2		4.3
OGE Energy [Member] | Total Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	117.7		139
Accumulated Depreciation	103.3		112.7
Net property, plant and equipment	14.4		26.3
OG&E [Member]
Property, Plant and Equipment [Line Items]
Capitalized Computer Software, Gross	36.5		34.3
Capitalized Computer Software, Amortization	8		6.9		$ 5.2
OG&E [Member] | Total Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	11,067.4		10,457.8
Accumulated Depreciation	3,385.6		3,161.7
Net property, plant and equipment	7,681.8		7,296.1
OG&E [Member] | Electric Transmission and Distribution [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	3,896.2		3,728.8
Accumulated Depreciation	1,221.5		1,152.8
Net property, plant and equipment	2,674.7		2,576
OG&E [Member] | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	4,155.9	[5]	3,837.4	[6]
Accumulated Depreciation	1,493.3	[5]	1,407	[6]
Net property, plant and equipment	2,662.6	[5]	2,430.4	[6]
Amount of Acquisition Adjustments	148.3		148.3
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	45.3		39.8
OG&E [Member] | Electric Transmission [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,548.8	[7]	2,454.2	[8]
Accumulated Depreciation	481.3	[7]	440.7	[8]
Net property, plant and equipment	2,067.5	[7]	2,013.5	[8]
Amount of Acquisition Adjustments	3.3		3.3
Amount of Acquistion Adjustments Related Accumulated Amortization	0.6		0.5
OG&E [Member] | Finite-Lived Intangible Assets, Major Class Name [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	85		81
Accumulated Depreciation	43.9		38
Net property, plant and equipment	41.1		43
OG&E [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	381.5		356.4
Accumulated Depreciation	145.6		123.2
Net property, plant and equipment	$ 235.9		$ 233.2
[1]	Construction work in progress was $0.2 million and $1.8 million for the McClain and Redbud Plants, respectively.
[2]	Construction work in progress was $1.6 million and $1.3 million for the McClain and Redbud Plants, respectively.
[3]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million.
[4]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million
[5]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $45.3 million.
[6]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $39.8 million.
[7]	This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million.
[8]	This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.5 million

Summary of Significant Accoun47

Summary of Significant Accounting Policies Depreciation and Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Provision for Depreciation Rate	3.00%	2.90%
Projected provision for depreciation in next fiscal year	3.10%
Percent Of Intangible Plant Balance Amortizable	97.00%
Percent of Intangible Plant Balance Amortizable Thereafter	3.00%
Transmission Equipment [Member] | OG&E [Member]
Amount of Acquisition Adjustments	$ 3.3
Redbud Plant [Member]
Amount of Acquisition Adjustments	$ 148.3	$ 148.3

Summary of Significant Accoun48

Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Current Fiscal Year End Date		--12-31
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1		$ 63.3	$ 58.6
Accretion expense		2.8	2.6
Revisions in estimated cash flows	[1]	3.6	1.6
Additions		0	0.9
Liabilities settled		(0.1)	(0.4)
Balance at December 31		$ 69.6	$ 63.3
[1]	Assumptions changed related to the estimated cost of asbestos abatement.

Summary of Significant Accoun49

Summary of Significant Accounting Policies Allowance for Funds Used During Construction (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, Allowance for Funds Used During Construction, Rate	8.20%	8.10%	6.90%

Summary of Significant Accoun50

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive (income) loss		$ (29.3)	$ (35.1)	$ (41.4)
Other comprehensive income before reclassifications		(0.5)	(0.2)
Amounts reclassified from accumulated other comprehensive income (loss)		(2.8)	(2.5)	(1.8)
Amounts reclassified from accumulated other comprehensive income (loss)		1.3	1.9
Net current period other comprehensive income (loss)		5.8	6.3
Amounts Reclassified from Accumulated OCI, Net of Tax and Noncontrolling Interest		6.3	6.5
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		(3.9)
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		(7.8)	(7.1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	[1]	(4.5)	(4.7)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Settlement Cost, before Tax	[1]	(8.2)	(7.5)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(12.7)	(12.2)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		(4.9)	(5.1)
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		1.5	0.6
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	[1]	0	(2)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	[1]	2.5	2.9
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		2.5	0.9
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		1	0.3
Defined Benefit Plans Income Loss [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		(32.1)	(39.2)	(36.8)
Other comprehensive income before reclassifications		(0.7)	(9.5)
Amounts reclassified from accumulated other comprehensive income (loss)		2.8	2.5
Net current period other comprehensive income (loss)		7.1	(2.4)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		(3.9)
Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		2.7	2.5	(8)
Other comprehensive income before reclassifications		0.2	9.3
Amounts reclassified from accumulated other comprehensive income (loss)		0	1.2
Net current period other comprehensive income (loss)		0.2	10.5
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		0
Defined Benefit Plan Prior Service Cost [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		0.1	0.1	0.1
Other comprehensive income before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income (loss)		0	0
Net current period other comprehensive income (loss)		0	0
Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		0	1.5	$ 3.3
Other comprehensive income before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive income (loss)		(1.5)	(1.8)
Net current period other comprehensive income (loss)		(1.5)	(1.8)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		0
Settlement Cost [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		5	4.6
Settlement Cost [Member] | Defined Benefit Plans Income Loss [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		5	4.6
Settlement Cost [Member] | Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		0	0
Settlement Cost [Member] | Defined Benefit Plan Prior Service Cost [Member] | Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		0	0
Settlement Cost [Member] | Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		$ 0	$ 0
[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Summary of Significant Accoun51

Summary of Significant Accounting Policies Enviromental Costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accrued Environmental Loss Contingencies, Noncurrent	$ 13.9	$ 10

Summary of Significant Accoun52

Summary of Significant Accounting Policies Summary of Significant Accounting Policies Reclassifications (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Prior Period Reclassification Adjustment		$ 1
Adjustments for New Accounting Pronouncement [Member]
Prior Period Reclassification Adjustment	$ 16.8

Accounting Pronouncements Emplo

Accounting Pronouncements Employee Share-Based Payment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Accounting Policies [Abstract]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 24.8

Investment in Unconsolidated 54

Investment in Unconsolidated Affiliate and Related Party Transactions (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Apr. 30, 2014	Dec. 31, 2016	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014	May 01, 2013
Schedule of Equity Method Investments [Line Items]
Accounts receivable - unconsolidated affiliates		$ 2.5		$ 2.5	$ 1.7
Limited Partner Units Owned		111		111
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.31800
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 743.7		$ 743.7	783.5
Equity in earnings of unconsolidated affiliates				101.8	15.5	[1]	$ 172.6
Enable Midstream Partners [Member]
Schedule of Equity Method Investments [Line Items]
Goodwill, Impairment Loss			$ 1,086.4
Partners' Capital Account, Units, Sold in Public Offering	25
Distributions received				$ 141.2	$ 139.3		143.7
Enogex LLC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Enogex LLC Contributed								100.00%
Increase in fair value of net assets								$ 2,200
OGE Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				25.70%	26.30%
Subordinated Units Held by Limited Partners of the LLC or LP				68.2
OGE Energy [Member]
Schedule of Equity Method Investments [Line Items]
Goodwill, Impairment Loss			$ 108.4	$ (2.6)	$ (178.4)
Percentage Share of Management Rights		50.00%		50.00%
CenterPoint [Member]
Schedule of Equity Method Investments [Line Items]
Percentage Share of Management Rights		50.00%		50.00%
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates				$ 101.8	$ 15.5	[1]	$ 172.6
[1]	In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment.

Investment in Unconsolidated 55

Investment in Unconsolidated Affiliate and Related Party Transactions Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Expected Settlement Charge	$ 21.4
Accounts receivable - unconsolidated affiliates	2.5	$ 1.7
Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	11.5	13.8	$ 13.3
Operating Costs Charged [Member] | OGE Energy [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	4.7	12.4	16.8
Natural Gas Transportation [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	35	35	34.9
Natural Gas Storage [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	0	0	4.4
Natural Gas Purchases [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	11.2	7.6	8.7
Employment Costs [Member] | OGE Energy [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	28.6	32.7	$ 104.8
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 2.7	$ 3.4

Investment in Unconsolidated 56

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Summarized Financial Information of Equity Method Investment [Line Items]
Current assets	$ 396	$ 381
Non-current assets	10,816	10,845
Current liabilities	362	615
Non-current liabilities	$ 3,056	$ 3,080

Investment in Unconsolidated 57

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Operating revenues	$ 2,272	$ 2,418	$ 3,367
Cost of natural gas and natural gas liquids	1,017	1,097	1,914
Operating income (loss)	385	(712)	586
Net income (loss)	$ 289.5	$ (752)	$ 530

Investment in Unconsolidated 58

Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Net income (loss)		$ 289.5	$ (752)		$ 530
Timing Differences Related to Equity Method Investee Net Income		(12.1)	12.1
Net Income Used to Calculate Equity in Earnings		268.3	(739.9)
Proportionate Unconsolidated Affiliate Net Income		70.7	(194.4)
OGE Energy's share of Enable net income (loss)		73.3	(16)
Amortization of basis difference		11.6	13.5
Elimination of Enable fair value step up		16.9	18
Equity in earnings of unconsolidated affiliates		101.8	15.5	[1]	172.6
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates		101.8	15.5	[1]	$ 172.6
Preferred Partner [Member]
Schedule of Equity Method Investments [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid		9.1	0
OGE Energy [Member]
Schedule of Equity Method Investments [Line Items]
Goodwill, Impairment Loss	$ (108.4)	$ 2.6	$ 178.4
[1]	In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment.

Investment in Unconsolidated 59

Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Basis Difference (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Basis Difference [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 743.7	$ 783.5
Elimination of Enable fair value step up	16.9	$ 18
OGE Energy [Member]
Reconciliation of Basis Difference [Line Items]
Goodwill, Impairment Loss	$ 11.3

Fair Value Measurements Carryin

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	$ 2,630.5	$ 2,738.8
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	2,385.5	2,493.9
Long-Term Debt, Fair Value	2,657.2	2,754.6
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	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]
Total long-term debt	9.9	10
Long-Term Debt, Fair Value	11.3	9.2
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	99.7	99.5
Long-Term Debt, Fair Value	99.9	99.9
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

Stock Based Compensation (Detai

Stock Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized		7,400,000
Tax Benefit from Compensation Expense		$ 1.8	$ 3.1	$ 3.3
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Minimum payout range		0.00%
Maximum payout range		200.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Total Compensation Cost Not yet Recognized		$ 8.2
Performance Units Related to Earnings Per Share [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		94,735	88,156	73,037
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 26.64	$ 33.99	$ 34.81
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number		221,350	241,470
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		94,735	88,156	73,037
Equity Instruments Other than Options, Converted in Period		(109,445)
Equity Instruments Other than Options, Forfeited in Period		(5,410)
Awards Other than Options, Fully Vested		61,742
Equity Instruments Other than Options, Converted, Aggregrate Intrinsic Value	[1]	$ 0
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		0
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		1.9
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 5.1
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Equity Instruments Other than Options, Nonvested, Number, Beginning Balance		132,316
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		94,735	88,156	73,037
Equity Instruments Other Than Options, Modification	[2]	(291)
Equity Instruments Other than Options, Vested in Period		(61,742)
Equity Instruments Other than Options, Forfeited in Period		(5,410)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		159,608	132,316
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 29.71	$ 34.30
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		26.64	$ 33.99	$ 34.81
Equity Instruments Other than Options, Modifications in Period, Weighted Average Grant Date Fair Value		33.01
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		34.83
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 31.95
Awards Other than Options, Vested and Expected to Vest, Outstanding	[2]	158,975
Equity Instruments Other than Options, Expected to Vest, Intrinsic Value		$ 0
Fair Value of Vested Performance Units and Restricted Stock		0	$ 0	$ 3.8
Total Compensation Cost Not yet Recognized		$ 2.3
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 7 months 17 days
Total Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		284,211	264,454	219,106
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 20.97	$ 31.02	$ 34.80
Expected Dividend Rate		3.50%	2.60%	2.50%
Expected Volatility Rate		19.80%	16.90%	20.00%
Risk Free Interest Rate		0.88%	0.91%	0.67%
Expected Term		2 years 10 months 2 days	2 years 10 months 6 days	2 years 10 months 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number		664,045	724,058
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		284,211	264,454	219,106
Equity Instruments Other than Options, Converted in Period		(327,988)
Equity Instruments Other than Options, Forfeited in Period		(16,236)
Awards Other than Options, Fully Vested		185,214
Equity Instruments Other than Options, Converted, Aggregrate Intrinsic Value	[1]	$ 0
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		0
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		17.3
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 15.3
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Equity Instruments Other than Options, Nonvested, Number, Beginning Balance		396,943
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		284,211	264,454	219,106
Equity Instruments Other Than Options, Modification	[2]	(873)
Equity Instruments Other than Options, Vested in Period		(185,214)
Equity Instruments Other than Options, Forfeited in Period		(16,236)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		478,831	396,943
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 25.16	$ 32.83
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		20.97	$ 31.02	$ 34.80
Equity Instruments Other than Options, Modifications in Period, Weighted Average Grant Date Fair Value		33.01
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		34.82
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 28.89
Awards Other than Options, Vested and Expected to Vest, Outstanding	[2]	476,920
Equity Instruments Other than Options, Expected to Vest, Intrinsic Value			$ 0
Fair Value of Vested Performance Units and Restricted Stock		$ 6.4	8.5	$ 9.5
Total Compensation Cost Not yet Recognized		$ 5.8
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 7 months 2 days
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 4.5	8.3	12
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Total Compensation Cost Not yet Recognized		8.1
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 0.1	$ 0.1	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		1,881	958	7,037
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 29.27	$ 26.11	$ 35.71
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding, Number		4,912	7,623
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		1,881	958	7,037
Equity Instruments Other than Options, Forfeited in Period		(268)
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		$ 0.1
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		$ 0.2
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Equity Instruments Other than Options, Nonvested, Number, Beginning Balance		7,623
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		1,881	958	7,037
Equity Instruments Other than Options, Vested in Period		(4,324)
Equity Instruments Other than Options, Forfeited in Period		(268)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		4,912	7,623
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 31.29	$ 29.68
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		29.27	$ 26.11	$ 35.71
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		32.98
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 37.31
Awards Other than Options, Vested and Expected to Vest, Outstanding		4,912
Fair Value of Vested Performance Units and Restricted Stock		$ 0.1	$ 0.2	$ 0.2
Total Compensation Cost Not yet Recognized		$ 0.1
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 6 months 18 days
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 4.6	8.4	12
Amount paid by unconsolidated affiliates		0	0.5	3.6
Compensation Expense, Net of Unconsolidated Affiliates		4.6	7.9	8.4
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		0	0.7	3.7
Total Shareholder Return [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 4.5	$ 7.6	$ 8.3
Common Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures		2,100	82,046	494,637
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Paid for Tax Withholding			901
[1]	These amounts represent performance units that vested at December 31, 2015 which were settled in February 2016.
[2]	The intrinsic value of the performance units based on total shareholder return and earnings per share is $15.3 million

Supplemental Cash Flow Inform62

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement		$ 39.5	$ 2.3	$ 0
SUPPLEMENTAL CASH FLOW INFORMATION
Interest (net of interest capitalized)	[1]	141.9	145.4	150.8
Income taxes (net of income tax refunds)		(5.9)	(3.4)	0.2
Interest costs capitalized		$ 7.5	$ 4.2	$ 2.4
[1]	Net of interest capitalized of $7.5 million, $4.2 million and $2.4 million in 2016, 2015 and 2014, respectively.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Federal Tax Expense (Benefit)		$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)		(5.7)	(5.2)	(4.5)
Current Income Tax Expense (Benefit)		(5.7)	(5.2)	(4.5)
Deferred Federal Income Tax Expense (Benefit)		126	98.8	160
Deferred State and Local Income Tax Expense (Benefit)		28	4.5	18.2
Deferred Income Tax Expense (Benefit)		154	103.3	178.2
Investment Tax Credit		(0.2)	(0.7)	(0.9)
Income Tax Expense (Benefit)		$ 148.1	$ 97.4	$ 172.8
Statutory Federal tax rate		35.00%	35.00%	35.00%
Federal renewable energy credit	[1]	(6.80%)	(8.90%)	(6.70%)
Remeasurement of state deferred tax liabilities		0.90%	(0.80%)	0.40%
401(k) dividends		(0.60%)	(0.70%)	(0.50%)
Federal investment tax credits, net		(0.80%)	(0.20%)	(0.20%)
State income taxes, net of Federal income tax benefit		1.90%	0.10%	1.20%
Uncertain tax positions		0.10%	0.70%	0.50%
Amortization of net unfunded deferred taxes		0.70%	0.90%	0.60%
Other		0.10%	0.30%	0.10%
Effective income tax rate		30.50%	26.40%	30.40%
Accrued liabilities		$ (16.1)	$ (14)
Accrued vacation		(3.5)	(3.2)
Uncollectible accounts		(0.6)	(0.5)
Accelerated depreciation and other property related differences		2,103.2	2,016
Investment in Enable Midstream Partners		657.3	623.4
Regulatory asset		34.4	32.7
Income taxes refundable to customers, net		24.1	22
Income taxes refundable to customers, net		16.5	13.7
Bond redemption-unamortized costs		4.3	4.8
Derivative instruments		2.2	1.5
Federal tax credits		(220.6)	(184.4)
State tax credits		(112.2)	(106.7)
Net operating losses		(31.7)	(94.6)
Accrued liabilities		(48.9)	(56.2)
Other		(34.6)	(46.3)
Asset retirement obligations		(24.5)	(22.5)
Deferred Federal investment tax credits		(0.8)	(0.9)
Other		(14)	(6.6)
Non-Current Deferred Income Tax Liabilities, net		2,334.5	2,178.2
Unrecognized Tax Benefits		20.7	20.2	$ 16.1	$ 12
Current year additions		0.5	4.1	4.1
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		0
Unrecognized Tax Benefits, Period Increase (Decrease)		0.5
Tax Credit Carryforward, Deferred Tax Asset		220.6	184.4
Employee Service Share-based Compensation, Unrecognized Tax Benefit from Compensation Expense		24.8
State operating loss [Member]
Operating Loss Carryforwards		554.7
Deferred Tax Assets, Operating Loss Carryforwards, State and Local		$ 20.4
Tax Credit Carryforward, Expiration Date		Dec. 31, 2030
Federal operating loss [Member]
Operating Loss Carryforwards		$ 32.2
Net operating losses		$ 11.3
Tax Credit Carryforward, Expiration Date		Dec. 31, 2030
Federal tax credits [Member]
Federal tax credits		$ (220.6)
Tax Credit Carryforward, Amount		220.6
Tax Credit Carryforward, Deferred Tax Asset		$ 220.6
Tax Credit Carryforward, Expiration Date		Dec. 31, 2029
Oklahoma investment tax credits [Member]
Federal tax credits		$ (88.2)
Tax Credit Carryforward, Amount		135.7
Tax Credit Carryforward, Deferred Tax Asset		88.2
Oklahoma capital investment board credits [Member]
Federal tax credits		(7.3)
Tax Credit Carryforward, Amount		7.3
Tax Credit Carryforward, Deferred Tax Asset		7.3
Oklahoma zero emission tax credits [Member]
Federal tax credits		(16.2)
Tax Credit Carryforward, Amount		24.1
Tax Credit Carryforward, Deferred Tax Asset		$ 16.2
Tax Credit Carryforward, Expiration Date		Dec. 31, 2020
Louisiana inventory credits [Member] [Member] [Domain]
Federal tax credits		$ (0.5)
Tax Credit Carryforward, Amount		0.7
Tax Credit Carryforward, Deferred Tax Asset		$ 0.5
Tax Credit Carryforward, Expiration Date		Dec. 31, 2019
State and Local Jurisdiction [Member]
Unrecognized Tax Benefits, Period Increase (Decrease)		$ 0.3
OGE Energy Corp. [Member]
Unrecognized Tax Benefits		13.7
Og and E [Member]
Unrecognized Tax Benefits		$ 13.5	$ 13.2	$ 10.5
[1]	Represents credits associated with the production from OG&E's wind farms.

Common Equity Automatic Dividen

Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Proceeds From Issuance of Shares Under Dividend Reinvestment Plan And Stock Purchase Plan		$ 7.2	$ 13.2
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, Dividend Reinvestment Plan and Stock Purchase Plan	0
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan	4,774,442

Common Equity Earnings Per Shar

Common Equity Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2016	[1]	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	[1]	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount																	0		0		0
Net income attributable to OGE Energy																	$ 338.2		$ 271.3		$ 395.8
Basic Average Common Shares Outstanding																	199.7		199.6		199.2
Contingently Issuable Shares (Performance and Restricted Stock Units)																	0.2		0		0.7
Diluted Average Common Shares Outstanding																	199.9		199.6		199.9
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.29		$ 0.92		$ 0.35		$ 0.13		$ 0.15		$ 0.55		$ 0.44		$ 0.22		$ 1.69	[1]	$ 1.36	[1]	$ 1.99
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.29		$ 0.92		$ 0.35		$ 0.13		$ 0.15		$ 0.55		$ 0.44		$ 0.22		$ 1.69	[1]	$ 1.36	[1]	$ 1.98
[1]	Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

Common Equity Dividends Restric

Common Equity Dividends Restriction (Details) shares in Millions, $ in Millions	Dec. 31, 2016USD ($)shares
Preferred Stock, Shares Outstanding | shares	0
OGE Energy [Member]
Ratio of Consolidated Debt to Consolidated Capitalization	65.00%
Retained Earnings, Restricted	$ 452.8
Retained Earnings, Unrestricted	$ 1,914.5
Og and E [Member]
Ratio of Consolidated Debt to Consolidated Capitalization	65.00%
Retained Earnings, Restricted	$ 351.5
Retained Earnings, Unrestricted	$ 1,900

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total long-term debt	$ 2,630.5	$ 2,738.8
Percent of Principal Amount Subject to Optional Tender	100.00%
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 225.2
Long-term Debt, Maturities, Repayments of Principal in Year Two	250.1
Long-term Debt, Maturities, Repayments of Principal in Year Three	250.1
Long-term Debt, Maturities, Repayments of Principal in Year Four	0.1
Long-term Debt, Maturities, Repayments of Principal in Year Five	$ 0.1
Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Date Due	Jan. 1, 2025
Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Date Due	Jan. 1, 2025
Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Date Due	Jun. 1, 2027
Redeemable during the next 12 months
Debt Instrument [Line Items]
Total long-term debt	$ 135.4
OG&E [Member] | Redeemable during the next 12 months | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Long term debt, gross	47	47
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Long term debt, gross	32.4	32.4
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Long term debt, gross	$ 56	$ 56
Minimum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.07%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.90%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.83%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.86%

Short-Term Debt and Credit Fa68

Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt		$ 236.2	$ 0
Line of Credit Facility [Abstract]
Aggregate Commitment		1,150
Amount Outstanding	[1]	$ 238
Weighted Average Interest Rate		0.95%
OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[2]	$ 750
Amount Outstanding	[2]	$ 236.2
Weighted Average Interest Rate	[2],[3]	0.95%
Maturity	[2],[4]	Dec. 13, 2018
OG&E [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[5]	$ 400
Letters of Credit Outstanding, Amount	[5]	$ 1.8
Weighted Average Interest Rate	[3],[5]	0.95%
Maturity	[4],[5]	Dec. 13, 2018
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800
[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2016.
[2]	This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.
[3]	Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
[4]	In December 2011, OGE Energy and OG&E entered into unsecured revolving credit agreements in the aggregate of $1,150.0 million ($750.0 million for OGE Energy and $400.0 million for OG&E) which expire in December 2018. OGE Energy and OG&E expect to replace the existing agreements with new revolving credit agreements during 2017, under terms and conditions generally similar to the existing agreements.
[5]	This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

Retirement Plans and Postreti69

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		3 Months Ended		12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions				$ 20	$ 0
Defined Contribution Plan, Employer Matching Contribution, Percent of Match				200.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay				5.00%
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost				$ 22.5	40.2	$ 19.3
Effect of One Percentage Point Increase on Service and Interest Cost Components				0	0	0
Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation				0.2	0.2	0.1
Effect of One Percentage Point Decrease on Service and Interest Cost Components				0	0.1	0.1
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation				0.7	0.7	0.7
Expected Future Benefit Payments, Next Twelve Months				48.7
Expected Future Benefit Payments, Year Two				48.7
Expected Future Benefit Payments, Year Three				51.9
Expected Future Benefit Payments, Year Four				54.6
Expected Future Benefit Payments, Year Five				55.7
Expected Future Benefit Payments, Five Fiscal Years Thereafter				290.1
Defined Contribution Plan, Cost Recognized				11.9	11.6	15.2
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation		$ 610.9		608	610.9
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning				680	725
Service cost				15.8	16.1	15.3
Interest cost				25.5	26.1	28.1
Plan settlements				0	(60.7)
Participants' contributions				0	0
Actuarial gains (losses)				4.7	(11.3)
Benefits paid				(53.8)	(15.2)
Benefit Obligation, Ending		680		672.2	680	725
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				581.7	679.8
Actual return on plans' assets				48	(22.2)
Employer contributions				20	0
Plan settlements				0	(60.7)
Participants' contributions				0	0
Benefits paid				(53.8)	(15.2)
Fair Value of Plan Assets, Ending		581.7		595.9	581.7	679.8
Funded Status of Plan		(98.3)		(76.3)	(98.3)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost				15.8	16.1	15.3
Interest cost				25.5	26.1	28.1
Expected return on plan assets				(41.5)	(46)	(45.3)
Amortization of net loss				16.5	18	14.3
Amortization of unrecognized prior service cost	[1]			(0.1)	0.4	1.7
Curtailment				0	0	(0.2)
Settlement		$ 5.5	$ 16.2	0	21.7	0
Net periodic benefit cost				16.2	36.3	13.9
Amount paid by unconsolidated affiliates				5.1	4.2	3.2
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]			11.1	32.1	10.7
Plan settlements				0	(60.7)
Capitalized Portion of Net Periodic Benefit Cost				$ 4	$ 5	$ 3.4
Assumptions Used Calculating Benefit Obligation, Discount Rate		4.00%		4.00%	4.00%	3.80%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets				7.50%	7.50%	7.50%
Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				4.20%	4.20%	4.20%
Fair Value of Plan Assets, Beginning				$ 581.7	$ 679.8
Pension Plans, Defined Benefit [Member] | OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements				9.9	(3.1)	$ 11.2
Pension Plans, Defined Benefit [Member] | ARKANSAS
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Plan settlements				0.1	1.9
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Plan settlements				0.1	1.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Plan settlements				0.1	1.9
Pension Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		$ 0			0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | U.S. common stocks [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				208.2
Fair Value of Plan Assets, Ending		208.2		237.1	208.2
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				208.2
Pension Plans, Defined Benefit [Member] | U.S. common stocks [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				208.2
Fair Value of Plan Assets, Ending		208.2		237.1	208.2
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				208.2
Pension Plans, Defined Benefit [Member] | U.S. common stocks [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | U.S. treasury notes and bonds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure	[3]	0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]			158.9
Fair Value of Plan Assets, Ending	[3]	158.9		122.3	158.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning	[3]			158.9
Pension Plans, Defined Benefit [Member] | U.S. treasury notes and bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]			158.9
Fair Value of Plan Assets, Ending	[3]	158.9		122.3	158.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning	[3]			158.9
Pension Plans, Defined Benefit [Member] | U.S. treasury notes and bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]			0
Fair Value of Plan Assets, Ending	[3]	0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning	[3]			0
Pension Plans, Defined Benefit [Member] | Mortgage-backed securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				14.5
Fair Value of Plan Assets, Ending		14.5		59.2	14.5
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				14.5
Pension Plans, Defined Benefit [Member] | Mortgage-backed securities | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Mortgage-backed securities | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				14.5
Fair Value of Plan Assets, Ending		14.5		59.2	14.5
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				14.5
Pension Plans, Defined Benefit [Member] | Corporate fixed income and other securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				140.2
Fair Value of Plan Assets, Ending		140.2		137.6	140.2
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				140.2
Pension Plans, Defined Benefit [Member] | Corporate fixed income and other securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Corporate fixed income and other securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				140.2
Fair Value of Plan Assets, Ending		140.2		137.6	140.2
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				140.2
Pension Plans, Defined Benefit [Member] | Commingled fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure	[4]	24.4		23.8	24.4
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[4]			24.4
Fair Value of Plan Assets, Ending	[4]	24.4		23.8	24.4
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning	[4]			24.4
Pension Plans, Defined Benefit [Member] | Commingled fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[4]			0
Fair Value of Plan Assets, Ending	[4]	0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning	[4]			0
Pension Plans, Defined Benefit [Member] | Commingled fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[4]			0
Fair Value of Plan Assets, Ending	[4]	0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning	[4]			0
Pension Plans, Defined Benefit [Member] | Foreign government bonds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				5.6
Fair Value of Plan Assets, Ending		5.6		5.2	5.6
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				5.6
Pension Plans, Defined Benefit [Member] | Foreign government bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Foreign government bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				5.6
Fair Value of Plan Assets, Ending		5.6		5.2	5.6
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				5.6
Pension Plans, Defined Benefit [Member] | Interest-bearing cash [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0			0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0.4
Fair Value of Plan Assets, Ending		0.4			0.4
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0.4
Pension Plans, Defined Benefit [Member] | Interest-bearing cash [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0.4
Fair Value of Plan Assets, Ending		0.4			0.4
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0.4
Pension Plans, Defined Benefit [Member] | Interest-bearing cash [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0			0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Municipal bonds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				4.9
Fair Value of Plan Assets, Ending		4.9		1.9	4.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				4.9
Pension Plans, Defined Benefit [Member] | Municipal bonds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Municipal bonds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				4.9
Fair Value of Plan Assets, Ending		4.9		1.9	4.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				4.9
Pension Plans, Defined Benefit [Member] | Money market funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		11.7		2.2	11.7
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				11.7
Fair Value of Plan Assets, Ending		11.7		2.2	11.7
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				11.7
Pension Plans, Defined Benefit [Member] | Money market funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Money market funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Mutual fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				24.3
Fair Value of Plan Assets, Ending		24.3		9	24.3
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				24.3
Pension Plans, Defined Benefit [Member] | Mutual fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				24.3
Fair Value of Plan Assets, Ending		24.3		9	24.3
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				24.3
Pension Plans, Defined Benefit [Member] | Mutual fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Treasury futures, receivable [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				17.6
Fair Value of Plan Assets, Ending		17.6		10.7	17.6
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				17.6
Pension Plans, Defined Benefit [Member] | Treasury futures, receivable [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Treasury futures, receivable [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				17.6
Fair Value of Plan Assets, Ending		17.6		10.7	17.6
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				17.6
Pension Plans, Defined Benefit [Member] | Treasury futures, payable [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				(12.4)
Fair Value of Plan Assets, Ending		(12.4)		(2.3)	(12.4)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				(12.4)
Pension Plans, Defined Benefit [Member] | Treasury futures, payable [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Treasury futures, payable [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				(12.4)
Fair Value of Plan Assets, Ending		(12.4)		(2.3)	(12.4)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				(12.4)
Pension Plans, Defined Benefit [Member] | Cash collateral [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure				0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending				0.3
Pension Plans, Defined Benefit [Member] | Cash collateral [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending				0.3
Pension Plans, Defined Benefit [Member] | Cash collateral [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending				0
Pension Plans, Defined Benefit [Member] | Receivable (foreign currency) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0		0	0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0.1
Fair Value of Plan Assets, Ending		0.1		0.2	0.1
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0.1
Pension Plans, Defined Benefit [Member] | Receivable (foreign currency) [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Receivable (foreign currency) [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0.1
Fair Value of Plan Assets, Ending		0.1		0.2	0.1
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0.1
Pension Plans, Defined Benefit [Member] | Payable (foreign currency) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0			0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				(0.1)
Fair Value of Plan Assets, Ending		(0.1)			(0.1)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				(0.1)
Pension Plans, Defined Benefit [Member] | Payable (foreign currency) [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0			0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Payable (foreign currency) [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				(0.1)
Fair Value of Plan Assets, Ending		(0.1)			(0.1)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				(0.1)
Pension Plans, Defined Benefit [Member] | Index fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0			0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				1.8
Fair Value of Plan Assets, Ending		1.8			1.8
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				1.8
Pension Plans, Defined Benefit [Member] | Index fund [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				1.8
Fair Value of Plan Assets, Ending		1.8			1.8
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				1.8
Pension Plans, Defined Benefit [Member] | Index fund [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0			0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Preferred stocks (foreign) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		0			0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0.3
Fair Value of Plan Assets, Ending		0.3			0.3
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0.3
Pension Plans, Defined Benefit [Member] | Preferred stocks (foreign) [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0.3
Fair Value of Plan Assets, Ending		0.3			0.3
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0.3
Pension Plans, Defined Benefit [Member] | Preferred stocks (foreign) [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0			0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Total Plan investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investments, Fair Value Disclosure		36.1		26	36.1
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				600.4
Fair Value of Plan Assets, Ending		600.4		607.2	600.4
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				600.4
Pension Plans, Defined Benefit [Member] | Total Plan investments [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				393.9
Fair Value of Plan Assets, Ending		393.9		368.7	393.9
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				393.9
Pension Plans, Defined Benefit [Member] | Total Plan investments [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				170.4
Fair Value of Plan Assets, Ending		170.4		212.5	170.4
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				170.4
Pension Plans, Defined Benefit [Member] | Receivable from broker for securities sold [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0
Fair Value of Plan Assets, Ending		0		0	0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				0
Pension Plans, Defined Benefit [Member] | Interest and dividends receivable [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				3.5
Fair Value of Plan Assets, Ending		3.5		3	3.5
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				3.5
Pension Plans, Defined Benefit [Member] | Payable to broker for securities purchased [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				(22.2)
Fair Value of Plan Assets, Ending		(22.2)		(14.3)	(22.2)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				(22.2)
Pension Plans, Defined Benefit [Member] | Total Plan assets [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				581.7
Fair Value of Plan Assets, Ending		581.7		595.9	581.7
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Fair Value of Plan Assets, Beginning				581.7
Restoration of Retirement Income Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation		24.6		6.1	24.6
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning				25.1	19.7
Service cost				0.3	1.3	1.1
Interest cost				0.4	0.7	0.6
Plan settlements				(20.6)	0
Participants' contributions				0	0
Actuarial gains (losses)				1.8	4
Benefits paid				0	(0.6)
Benefit Obligation, Ending		25.1		7	25.1	19.7
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning				0	0
Actual return on plans' assets				0	0
Employer contributions				20.6	0.6
Plan settlements				(20.6)	0
Participants' contributions				0	0
Benefits paid				0	(0.6)
Fair Value of Plan Assets, Ending		0		0	0	0
Funded Status of Plan		$ (25.1)		(7)	(25.1)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost				0.3	1.3	1.1
Interest cost				0.4	0.7	0.6
Expected return on plan assets				0	0	0
Amortization of net loss				0.7	0.6	0.2
Amortization of unrecognized prior service cost	[1]			0.1	0.1	0.2
Curtailment				0	0	0
Settlement				8.6	0	0
Net periodic benefit cost				10.1	2.7	2.1
Amount paid by unconsolidated affiliates				0.3	0.1	0.1
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]			9.8	2.6	$ 2
Plan settlements				(20.6)	0
Fair Value of Plan Assets, Beginning				$ 0	$ 0
Less Than 90% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				50.00%
Projected Benefit Obligation Funded Status Thresholds Equity				50.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
95% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				58.00%
Projected Benefit Obligation Funded Status Thresholds Equity				42.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
100% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				65.00%
Projected Benefit Obligation Funded Status Thresholds Equity				35.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
105% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				73.00%
Projected Benefit Obligation Funded Status Thresholds Equity				27.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
110% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				80.00%
Projected Benefit Obligation Funded Status Thresholds Equity				20.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
115% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				85.00%
Projected Benefit Obligation Funded Status Thresholds Equity				15.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
120% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Projected Benefit Obligation Funded Status Thresholds Fixed Income				90.00%
Projected Benefit Obligation Funded Status Thresholds Equity				10.00%
Projected Benefit Obligation Funded Status Thresholds				100.00%
Domestic All-Cap/Large Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Target Plan Asset Allocations				40.00%
Target Plan Asset Allocations Range Minimum				35.00%
Target Plan Asset Allocations Range Maximum				60.00%
Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Target Plan Asset Allocations				15.00%
Target Plan Asset Allocations Range Minimum				5.00%
Target Plan Asset Allocations Range Maximum				25.00%
Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Target Plan Asset Allocations				25.00%
Target Plan Asset Allocations Range Minimum				5.00%
Target Plan Asset Allocations Range Maximum				30.00%
International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Target Plan Asset Allocations				20.00%
Target Plan Asset Allocations Range Minimum				10.00%
Target Plan Asset Allocations Range Maximum				30.00%
[1]	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
[2]	In addition to the $22.5 million, $40.2 million and $19.3 million of net periodic benefit cost recognized in 2016, 2015 and 2014, respectively, OG&E recognized the following: •a change in pension expense in 2016, 2015 and 2014 of $9.9 million, $(3.1) million and $11.2 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 asset or liability (see Note 1); •an increase in postretirement medical expense in 2016, 2015 and 2014 of $7.9 million, $5.8 million and $5.2 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and •a deferral of pension expense in 2016 and 2015 of $0.1 million and $1.9 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.6 million and $21.7 million, respectively.
[3]	This category represents U.S. treasury notes and bonds with a Moody's Investors Services rating of Aaa and Government Agency Bonds with a Moody's Investors Services rating of A1 or higher.
[4]	This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

Retirement Plans and Postreti70

Retirement Plans and Postretirement Benefit Plans Postretirement Benefit Plans (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost		$ 22.5	$ 40.2	$ 19.3
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Level 3 Asset Value, Beginning of Period		46.8
Interest income		0.9
Dividend income		0.6
Unrealized gains		0.2
Realized losses		(0.1)
Claims paid		(3.7)
Level 3 Asset Value, End of Period		44.7	46.8
Postretirement Plan, Expected Future Benefit Payments, Next Twelve Months		14
Postretirement Plan, Expected Future Benefit Payments, Year Two		14.1
Postretirement Plan, Expected Future Benefit Payments, Year Three		14.1
Postretirement Plan, Expected Future Benefit Payments in Year Four		14.1
Postretirement Plan, Expected Future Benefit Payments, Year Five		14.1
Postretirement Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter		69.1
Postemployment Benefits Liability		2.4	1.5
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		225.3	280.9
Service cost		0.8	1.5	3.1
Interest cost		9.5	10.3	11.4
Plan settlements		0	0
Participants' contributions		3.6	3.4
Actuarial gains (losses)		(7.6)	(55.1)
Benefits paid		(15.7)	(15.7)
Benefit Obligation, Ending		215.9	225.3	280.9
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		55.3	59.6
Actual return on plans' assets		2	(0.5)
Employer contributions		7.9	8.5
Plan settlements		0	0
Participants' contributions		3.6	3.4
Benefits paid		(15.7)	(15.7)
Fair Value of Plan Assets, Ending		53.1	55.3	59.6
Funded Status of Plan		(162.8)	(170)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		0.8	1.5	3.1
Interest cost		9.5	10.3	11.4
Expected return on plan assets		(2.3)	(2.4)	(2.4)
Amortization of net loss		2.6	13.9	12.3
Amortization of unrecognized prior service cost	[1]	(8.8)	(16.5)	(16.5)
Curtailment		0	0	0
Settlement		0	0	0
Net periodic benefit cost		1.8	6.8	7.9
Amount paid by unconsolidated affiliates		0.2	1.3	1.3
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]	1.6	5.5	6.6
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Capitalized Portion of Net Periodic Benefit Cost		$ 0.8	$ 1.9	$ 2
Assumptions Used Calculating Benefit Obligation, Discount Rate		4.20%	4.25%	3.80%
Health Care Cost Trend Rate Assumed for Next Fiscal Year		6.75%	6.10%	7.85%
Ultimate Health Care Cost Trend Rate		4.50%	4.50%	4.48%
Year that Rate Reaches Ultimate Trend Rate		2,026	2,026	2,028
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		4.00%	4.00%	4.00%
Other Postretirement Benefit Plans, Defined Benefit [Member] | Group Retiree Medical Insurance Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]	$ 46.8
Fair Value of Plan Assets, Ending	[3]	44.7	$ 46.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | U.S. Equity Mutual Funds Investment [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		7.8
Fair Value of Plan Assets, Ending		8.1	7.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.7
Fair Value of Plan Assets, Ending			0.7
Other Postretirement Benefit Plans, Defined Benefit [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.3
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		8.5
Fair Value of Plan Assets, Ending		8.4	8.5
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Group Retiree Medical Insurance Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]	0
Fair Value of Plan Assets, Ending	[3]	0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | U.S. Equity Mutual Funds Investment [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		7.8
Fair Value of Plan Assets, Ending		8.1	7.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.7
Fair Value of Plan Assets, Ending			0.7
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0.3
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0
Fair Value of Plan Assets, Ending		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		46.8
Fair Value of Plan Assets, Ending		44.7	46.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Group Retiree Medical Insurance Contract [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]	46.8
Fair Value of Plan Assets, Ending	[3]	44.7	46.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | U.S. Equity Mutual Funds Investment [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0
Fair Value of Plan Assets, Ending		0	0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Money market funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0
Fair Value of Plan Assets, Ending			0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0
OKLAHOMA | Other Postretirement Benefit Plans, Defined Benefit [Member]
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Additional Postretirement Medical Expense to Meet State Requirements		$ 7.9	$ 5.8	$ 5.2
[1]	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.
[2]	In addition to the $22.5 million, $40.2 million and $19.3 million of net periodic benefit cost recognized in 2016, 2015 and 2014, respectively, OG&E recognized the following: •a change in pension expense in 2016, 2015 and 2014 of $9.9 million, $(3.1) million and $11.2 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 asset or liability (see Note 1); •an increase in postretirement medical expense in 2016, 2015 and 2014 of $7.9 million, $5.8 million and $5.2 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and •a deferral of pension expense in 2016 and 2015 of $0.1 million and $1.9 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.6 million and $21.7 million, respectively.
[3]	This category represents a group retiree medical insurance contract which invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities.

Report of Business Segments (De

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating revenues	$ 530.8	$ 743.9	$ 551.4	$ 433.1	$ 447.1	$ 719.8	$ 549.9	$ 480.1		$ 2,259.2	$ 2,196.9		$ 2,453.1
Cost of sales										880.1	865		1,106.6
Other operation and maintenance										465.6	451.6		439.6
Depreciation and amortization										322.6	307.9		281.4
Taxes other than income										87.6	91.2		88.7
Operating income (loss)	82.2	257.3	125.9	37.9	46.8	250.8	127.2	56.4		503.3	481.2		536.8
Equity in earnings of unconsolidated affiliates										101.8	15.5	[1]	172.6
Other income (expense)										23.3	21		7.6
Interest expense										142.1	149		148.4
Income tax expense (benefit)										148.1	97.4		172.8
NET INCOME	57.9	$ 183.6	$ 71.5	$ 25.2	29.4	$ 111.2	$ 87.5	$ 43.2		338.2	271.3		395.8
NET INCOME ATTRIBUTABLE TO OGE ENERGY										338.2	271.3		395.8
Investment in unconsolidated affiliates	1,158.6				1,194.4					1,158.6	1,194.4		1,318.2
Total assets	9,939.6				9,580.6					9,939.6	9,580.6		9,509.9
Capital expenditures										660.1	547.8		569.3
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues										2,259.2	2,196.9		2,453.1
Cost of sales										880.1	865		1,106.6
Other operation and maintenance										469.8	444.5		453.2
Depreciation and amortization										316.4	299.9		270.8
Taxes other than income										84	87.1		84.5
Operating income (loss)										508.9	500.4		538
Equity in earnings of unconsolidated affiliates										0	0	[1]	0
Other income (expense)										27.7	20		7.1
Interest expense										138.1	146.7		141.5
Income tax expense (benefit)										114.4	104.8		111.6
NET INCOME										284.1	268.9		292
Investment in unconsolidated affiliates	0				0					0	0		0
Total assets	8,669.4				8,525.5					8,669.4	8,525.5		8,248.9
Capital expenditures										660.1	551.6		565.4
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues										0	0		0
Cost of sales										0	0		0
Other operation and maintenance										7.7	7.5		1.2
Depreciation and amortization										0	0		0
Taxes other than income										0	0		0
Operating income (loss)										(7.7)	(7.5)		(1.2)
Equity in earnings of unconsolidated affiliates										101.8	15.5	[1]	172.6
Other income (expense)										0.1	0.4		0
Interest expense										0	0		0
Income tax expense (benefit)										40.5	(1)		69.1
NET INCOME										53.7	9.4		102.3
Investment in unconsolidated affiliates	1,158.6				1,194.4					1,158.6	1,194.4		1,318.2
Total assets	1,521.6				1,439.5					1,521.6	1,439.5		1,461.2
Capital expenditures										0	0		0
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues										0	0		0
Cost of sales										0	0		0
Other operation and maintenance										(11.9)	(0.4)		(14.8)
Depreciation and amortization										6.2	8		10.6
Taxes other than income										3.6	4.1		4.2
Operating income (loss)										2.1	(11.7)		0
Equity in earnings of unconsolidated affiliates										0	0	[1]	0
Other income (expense)										(4.3)	0.9		0.7
Interest expense										4.2	2.6		7.1
Income tax expense (benefit)										(6.8)	(6.4)		(7.9)
NET INCOME										0.4	(7)		1.5
Investment in unconsolidated affiliates	0				0					0	0		0
Total assets	89				174.6					89	174.6		128.6
Capital expenditures										0	(3.8)		10.8
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues										0	0		0
Cost of sales										0	0		0
Other operation and maintenance										0	0		0
Depreciation and amortization										0	0		0
Taxes other than income										0	0		0
Operating income (loss)										0	0		0
Equity in earnings of unconsolidated affiliates										0	0	[1]	0
Other income (expense)										(0.2)	(0.3)		(0.2)
Interest expense										(0.2)	(0.3)		(0.2)
Income tax expense (benefit)										0	0		0
NET INCOME										0	0		0
Investment in unconsolidated affiliates	0				0					0	0		0
Total assets	$ (340.4)				$ (559)					(340.4)	(559)		(328.8)
Capital expenditures										0	0		$ (6.9)
OGE Energy [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss									$ 108.4	$ (2.6)	$ (178.4)
[1]	In 2015, The Company recorded a $108.4 million pre-tax charge during the third quarter of 2015 for its share of the goodwill impairment, as adjusted for the basis difference. See Note 3 for further discussion of Enable's goodwill impairment.

Commitments and Contingencies72

Commitments and Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 15, 2015USD ($)
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 6
Operating Leases, Future Minimum Payments, Due in Two Years	4.9
Operating Leases, Future Minimum Payments, Due in Three Years	23.5
Operating Leases, Future Minimum Payments, Due in Four Years	2.9
Operating Leases, Future Minimum Payments, Due in Five Years	2.9
Operating Leases, Future Minimum Payments, Due Thereafter	43.5
Operating Leases, Future Minimum Payments Due	83.7
Operating Leases, Rent Expense, Net	9.3	$ 7.7	$ 6.7
Purchase Obligation, Due in Next Twelve Months	711.8
Unrecorded Unconditional Purchase Obligation, Due within Two Years	331.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	229.3
Unrecorded Unconditional Purchase Obligation, Due within Four Years	179.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	179.9
Long-term Purchase Commitment, Amount	1,632.6
Utilities Operating Expense, Purchased Power under Long-term Contracts	61	56.6	60.8
Contract Amount				$ 170.3
OG&E Railcar Lease Agreement [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	2.7
Operating Leases, Future Minimum Payments, Due in Two Years	1.7
Operating Leases, Future Minimum Payments, Due in Three Years	21
Operating Leases, Future Minimum Payments, Due in Four Years	0
Operating Leases, Future Minimum Payments, Due in Five Years	0
Operating Leases, Future Minimum Payments, Due Thereafter	0
Operating Leases, Future Minimum Payments Due	25.4
OG&E Wind Farm Land Lease Agreements [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	2.5
Operating Leases, Future Minimum Payments, Due in Two Years	2.5
Operating Leases, Future Minimum Payments, Due in Three Years	2.5
Operating Leases, Future Minimum Payments, Due in Four Years	2.9
Operating Leases, Future Minimum Payments, Due in Five Years	2.9
Operating Leases, Future Minimum Payments, Due Thereafter	43.5
Operating Leases, Future Minimum Payments Due	56.8
OGE Energy Building Lease [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	0.8
Operating Leases, Future Minimum Payments, Due in Two Years	0.7
Operating Leases, Future Minimum Payments, Due in Three Years	0
Operating Leases, Future Minimum Payments, Due in Four Years	0
Operating Leases, Future Minimum Payments, Due in Five Years	0
Operating Leases, Future Minimum Payments, Due Thereafter	0
Operating Leases, Future Minimum Payments Due	1.5
OG&E cogeneration capacity and fixed operation and maintenance payments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	77.1
Unrecorded Unconditional Purchase Obligation, Due within Two Years	73.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	66.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	54.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	51
Long-term Purchase Commitment, Amount	323.2
OG&E expected cogeneration energy payments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	37.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	37.5
Unrecorded Unconditional Purchase Obligation, Due within Three Years	38.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	40.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	44.4
Long-term Purchase Commitment, Amount	199.2
OG&E minimum fuel purchase commitments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	236.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	49.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	36.2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	24.6
Unrecorded Unconditional Purchase Obligation, Due within Five Years	24.6
Long-term Purchase Commitment, Amount	370.9
OG&E expected wind purchase commitments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	59
Unrecorded Unconditional Purchase Obligation, Due within Two Years	57.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	56.6
Unrecorded Unconditional Purchase Obligation, Due within Four Years	57.1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	57.5
Long-term Purchase Commitment, Amount	288.1
OG&E long-term service agreement commitments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	2.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	28.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	22.2
Unrecorded Unconditional Purchase Obligation, Due within Four Years	2.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	2.4
Long-term Purchase Commitment, Amount	57.6
Mustang Modernization [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	130.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	21.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Long-term Purchase Commitment, Amount	152.3
Environmental compliance plan expenditures [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	169.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	63
Unrecorded Unconditional Purchase Obligation, Due within Three Years	8.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Long-term Purchase Commitment, Amount	$ 241.3
Public Utility Regulatory Policy Act of 1978 [Member]
Loss Contingencies [Line Items]
Percentage of output purchased	100.00%
OG&E total cogeneration payments [Member]
Loss Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 124.8	124	129.4
OG&E capacity payments [Member]
Loss Contingencies [Line Items]
Long-term Purchase Commitment, Amount	66.3	69.5	72.3
CPV Keenan [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	29.2	26.7	28.1
Edison Mission Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	21.1	19.7	21.3
FPL Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	3.4	3.2	3.6
NextEra Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	$ 7.3	$ 7	$ 7.8
OG&E long-term service agreement commitments [Member] | McClain Plant [Member]
Loss Contingencies [Line Items]
Factored-Fired Hours	128,000
Factored-Fired Starts	4,800
OG&E long-term service agreement commitments [Member] | Redbud Plant [Member]
Loss Contingencies [Line Items]
Factored-Fired Hours	144,000
Factored-Fired Starts	4,500
Additional Factored-Fired Hours	24,000
Clean Power Plan [Member]
Loss Contingencies [Line Items]
Proposed Rate-Based Carbon Reduction	43.00%
Final Rate-Based Carbon Reduction	32.00%
Mass-Based Carbon Reduction	24.00%
Maximum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Maximum	$ 18.3

Rate Matters and Regulation (De

Rate Matters and Regulation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Additional Requested Plant Dismantlement Cost	$ 8
Change in Requested Return on Equity	0.25%
Change in Requested Rate Increase	$ 9
Administrative Law Judge [Member]
Recommended Return on Equity	9.87%
Recommended Increase (Decrease) in Revenue	$ 40.7
Recommended Capital Structure, Equity Percentage	53.00%
Recommended Capital Structure, Debt Percentage	47.00%
Oklahoma Corporation Commission [Member]
OG&E's Jurisdictional Revenues	86.00%
Arkansas Public Service Commission [Member]
OG&E's Jurisdictional Revenues	8.00%
Federal Energy Regulatory Commission [Member]
OG&E's Jurisdictional Revenues	6.00%
Oklahoma Public Utility Division Staff [Member]
Recommended Return on Equity	9.25%
Reduction to Requested Additional Plant Dismantlement Costs	$ 33
Recommended Rate Increase (Decrease)	$ 6.1
Recommended Common Equity Percentage	53.00%
Oklahoma Attorney General [Member]
Reduction to Requested Additional Plant Dismantlement Costs	$ 20.9
Oklahoma Industrial Electric Consumers [Member]
Recommended Return on Equity	9.00%
Reduction to Requested Additional Plant Dismantlement Costs	$ 52.5
Recommended Rate Increase (Decrease)	$ (47.9)
Recommended Common Equity Percentage	53.00%
SmartHours Program [Member]
Lost Revenue Associated with Customer Programs - recovered annually	$ 10.1
Lost Revenue Associated with Customer Programs	30.3
Amount Recorded for Lost Revenue Associated with Customer Programs	36.6
Dry Scrubber Project [Member]
Estimated Environmental Capital Costs	547.5
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	208.7
Mustang Modernization [Member]
Estimated Environmental Capital Costs	424.9
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	$ 187.8
OKLAHOMA
Public Utilities, Requested Equity Capital Structure, Percentage	53.00%
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 92.5
Public Utilities, Requested Return on Equity, Percentage	10.25%
Investments Since Last Rate Case	$ 1,600
Public Utilities, Interim Rate Increase (Decrease), Amount	69.5
Interim Rate Collected	39
Interim Rate Revenue Reserved	33.7
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
Change in Allowed Amount [Member] | SmartHours Program [Member]
Lost Revenue Associated with Customer Programs	$ (6.3)
Recommendation 1 [Member] | Oklahoma Attorney General [Member]
Recommended Return on Equity	9.25%
Recommended Rate Increase (Decrease)	$ (10.8)
Recommended Common Equity Percentage	50.00%
Recommendation 2 [Member] | Oklahoma Attorney General [Member]
Recommended Return on Equity	8.90%
Recommended Rate Increase (Decrease)	$ (13.7)
Recommended Common Equity Percentage	53.00%

Quarterly Financial Data (Detai

Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Operating revenues	$ 530.8		$ 743.9		$ 551.4		$ 433.1		$ 447.1		$ 719.8		$ 549.9		$ 480.1		$ 2,259.2		$ 2,196.9		$ 2,453.1
Operating income	82.2		257.3		125.9		37.9		46.8		250.8		127.2		56.4		503.3		481.2		536.8
Net income	$ 57.9		$ 183.6		$ 71.5		$ 25.2		$ 29.4		$ 111.2		$ 87.5		$ 43.2		$ 338.2		$ 271.3		$ 395.8
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.29	[1]	$ 0.92	[1]	$ 0.35	[1]	$ 0.13	[1]	$ 0.15	[1]	$ 0.55	[1]	$ 0.44	[1]	$ 0.22	[1]	$ 1.69	[1]	$ 1.36	[1]	$ 1.99
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.29	[1]	$ 0.92	[1]	$ 0.35	[1]	$ 0.13	[1]	$ 0.15	[1]	$ 0.55	[1]	$ 0.44	[1]	$ 0.22	[1]	$ 1.69	[1]	$ 1.36	[1]	$ 1.98
[1]	Due to the impact of dilution on the earnings per share calculation, quarterly earnings per share amounts may not add to the total.

Schedule II (Details)

Schedule II (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance		$ 1.4	$ 1.6	$ 1.9
Valuation Allowances and Reserves, Charged to Cost and Expense		2.5	2.4	2.3
Valuation Allowances and Reserves, Deductions	[1]	2.4	2.6	2.6
Valuation Allowances and Reserves, Ending Balance		$ 1.5	$ 1.4	$ 1.6
[1]	Uncollectible accounts receivable written off, net of recoveries.