OGE Energy (OGE) 10-K 21 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document	12 Months Ended
	Dec. 31, 2018USD ($)shares
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, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding | shares	199,732,315
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float | $	$ 7,032,567,628

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Revenue from Contract with Customer, Excluding Assessed Tax	$ 2,211.7		$ 0		$ 0
Revenues from Alternative Revenue Programs	58.6		0		0
OPERATING REVENUES
Total operating revenues	2,270.3		2,261.1		2,259.2
Total cost of sales	892.5		897.6		880.1
OPERATING EXPENSES
Other operation and maintenance	474.6		458.7		438.1
Depreciation and amortization	321.6		283.5		322.6
Taxes other than income	92		89.4		87.6
Operating expenses	888.2		831.6		848.3
Operating income (loss)	489.6		531.9		530.8
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	152.8		131.2		101.8
Allowance for equity funds used during construction	23.8		39.7		14.2
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	(10.8)		(21.6)		(27.5)
Other income	21.7		46.4		26
Other expense	(23.4)		(14.1)		(16.9)
Net other income	164.1		181.6		97.6
INTEREST EXPENSE
Interest on long-term debt	157.4		153.6		143.2
Allowance for borrowed funds used during construction	(11.7)		(18)		(7.5)
Interest on short-term debt and other interest charges	10.3		8.2		6.4
Interest expense	156		143.8		142.1
INCOME BEFORE TAXES	497.7		569.7		486.3
INCOME TAX EXPENSE (BENEFIT)	72.2		(49.3)	[1]	148.1
NET INCOME	$ 425.5		$ 619		$ 338.2
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7		199.7		199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.5		200		199.9
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 2.13	[2]	$ 3.10	[2]	$ 1.69
DILUTED EARNINGS PER AVERAGE COMMON SHARE	2.12	[2]	3.10	[2]	1.69
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.39500		$ 1.27000		$ 1.15500
[1]	The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act. See Note 8 for further discussion of the effects of the 2017 Tax Act.
[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, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income	$ 425.5	$ 619	$ 338.2
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $1.1, $1.4 and $1.7, respectively	3.3	2.5	2.8
Amortization of prior service cost, net of tax of $0.0, $0.0 and $0.0, respectively	0	(0.1)	0
Net gain (loss) arising during the period, net of tax of ($4.7), $0.2 and ($0.6), respectively	(14.1)	0.4	(0.7)
Settlement cost, net of tax of $1.6, $1.4 and $3.2, respectively	4.7	2.2	5
Postretirement Benefit Plans:
Amortization of prior service credit, net of tax of ($0.6), ($0.3) and ($1.0), respectively	(1.7)	(0.6)	(1.5)
Prior service cost arising during the period, net of tax of $0.0, $4.0 and $0.0, respectively	0	6.3	0
Net gain (loss) arising during the period, net of tax of $0.7, ($0.2) and $0.1, respectively	2.1	(0.6)	0.2
Settlement cost, net of tax of $0.0, $0.2 and $0.0, respectively	0	0.5	0
Other comprehensive income (loss), net of tax	(5.7)	10.6	5.8
Comprehensive income	$ 419.8	$ 629.6	$ 344

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $1.1, $1.4 and $1.7, respectively	$ 1.1	$ 1.4	$ 1.7
Net gain (loss) arising during the period, net of tax of ($4.7), $0.2 and ($0.6), respectively	(4.7)	0.2	(0.6)
Amortization of prior service cost, net of tax of $0.0, $0.0 and $0.0, respectively	0	0	0
Postretirement plans:
Prior service cost arising during the period, net of tax of $0.0, $4.0 and $0.0, respectively	0	(4)	0
Amortization of deferred net loss, net of tax of $0.0, $0.0 and $0.0, respectively	0	0	0
Net gain (loss) arising during the period, net of tax of $0.7, ($0.2) and $0.1, respectively	0.7	(0.2)	0.1
Amortization of prior service credit, net of tax of ($0.6), ($0.3) and ($1.0), respectively	(0.6)	(0.3)	(1)
Amortization of deferred interest rate swap hedging losses, net of tax of $0, $0 and $0.0, respectively	0	0	0
Pension Plans [Member]
Pension Plan and Restoration of Retirement Income Plan:
Settlement cost, net of tax of $1.6, $1.4 and $3.2, respectively	1.6	1.4	3.2
Other Postretirement Benefits Plan [Member]
Pension Plan and Restoration of Retirement Income Plan:
Settlement cost, net of tax of $1.6, $1.4 and $3.2, respectively	$ 0	$ 0.2
Postretirement plans:
Settlement cost, net of tax of $0.0, $0.2 and $0.0, respectively			$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 425.5	$ 619	$ 338.2
Adjustments to reconcile net income to net cash provided from operating activities:
Depreciation and amortization	321.6	283.5	322.6
Deferred income taxes and investment tax credits, net	78.5	(50)	153.8
Equity in earnings of unconsolidated affiliates	(152.8)	(131.2)	(101.8)
Distributions from unconsolidated affiliates	141.2	131.2	102.3
Allowance for equity funds used during construction	(23.8)	(39.7)	(14.2)
Stock-based compensation expense	13.4	9.1	4.7
Regulatory assets	10.8	(3.7)	21.4
Regulatory liabilities	(16.5)	(3.7)	(11.8)
Other assets	6.2	(0.7)	15.4
Other liabilities	1	(65.5)	(18.9)
Change in certain current assets and liabilities:
Accounts receivable and accrued unbilled revenues, net	19.8	(21.8)	(6.9)
Income taxes receivable	(4.1)	13.6	(2.2)
Fuel, materials and supplies inventories	27.3	(3.6)	32.4
Fuel recoveries	(3.4)	53	(112.6)
Other current assets	25.1	27.2	(26.2)
Accounts payable	29.7	27.1	(45.1)
Other current liabilities	73.2	(66.7)	36.4
Net cash provided from operating activities	951.1	784.5	644.7
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(573.6)	(824.1)	(660.1)
Investment in unconsolidated affiliates	(2.5)	(8.5)	0
Return of capital - unconsolidated affiliates	0	10	38.8
Proceeds from sale of assets	0.1	0.7	0.9
Net cash used in investing activities	(576)	(821.9)	(620.4)
CASH FLOWS FROM FINANCING ACTIVITIES
(Decrease) increase in short-term debt	(168.4)	(67.8)	236.2
Proceeds from long-term debt	396	592.1	0
Payment of long-term debt	(250.1)	(225.1)	(110.2)
Dividends paid on common stock	(272.2)	(247.6)	(225.1)
Expense of common stock	(0.1)	(0.1)	0
Other	(0.4)	0	(0.1)
Net cash (used in) provided from financing activities	(295.2)	51.5	(99.2)
NET CHANGE IN CASH AND CASH EQUIVALENTS	79.9	14.1	(74.9)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	14.4	0.3	75.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 94.3	$ 14.4	$ 0.3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS
Cash and cash equivalents	$ 94.3	$ 14.4
Accounts receivable, less reserve of $1.7 and $1.5, respectively	174.7	190.6
Accrued unbilled revenues	62.6	66.5
Income taxes receivable	9.9	5.8
Fuel inventories	57.6	84.3
Materials and supplies, at average cost	126.7	80.8
Fuel clause under recoveries	2	0
Other	29.5	54.6
Total current assets	557.3	497
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,177.5	1,160.4
Other	73.4	76.7
Total other property and investments	1,250.9	1,237.1
PROPERTY, PLANT AND EQUIPMENT
In service	11,994.8	11,041.2
Construction work in progress	376.4	867.5
Total property, plant and equipment	12,371.2	11,908.7
Less accumulated depreciation	3,727.4	3,568.8
Net property, plant and equipment	8,643.8	8,339.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	285.8	283
Other	10.8	55.7
Total deferred charges and other assets	296.6	338.7
TOTAL ASSETS	10,748.6	10,412.7
CURRENT LIABILITIES
Short-term debt	0	168.4
Accounts payable	239.3	230.4
Dividends payable	72.9	66.4
Customer deposits	83.6	80.7
Accrued taxes	44	44.5
Accrued interest	44.5	44
Accrued compensation	47.8	35.9
Long-term debt due within one year	250	249.8
Fuel clause over recoveries	0.3	1.7
Other	87	28.7
Total current liabilities	869.4	950.5
LONG-TERM DEBT	2,896.9	2,749.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	225.7	192.7
Deferred income taxes	1,310.9	1,227.8
Regulatory liabilities	1,270.7	1,283.4
Other	169.9	157.6
Total deferred credits and other liabilities	2,977.2	2,861.5
Total liabilities	6,743.5	6,561.6
COMMITMENTS AND CONTINGENCIES (NOTE 14)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,127.7	1,114.8
Retained earnings	2,906.3	2,759.5
Accumulated other comprehensive loss, net of tax	(28.9)	(23.2)
Total stockholders' equity	4,005.1	3,851.1
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 10,748.6	$ 10,412.7

CONSOLIDATED BALANCE SHEETS Par

CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Allowance for Doubtful Accounts Receivable	$ 1.7	$ 1.5

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
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	1,125.7	1,112.8
Retained earnings	2,906.3	2,759.5
Accumulated other comprehensive loss, net of tax	(28.9)	(23.2)
Total stockholders' equity	4,005.1	3,851.1
Unamortized debt expense	(22.9)	(20.8)
Total long-term debt	3,146.9	2,999.4
Less: long-term debt due within one year	(250)	(249.8)
Total long-term debt (excluding long-term debt due within one year)	2,896.9	2,749.6
Total capitalization (including long-term debt due within one year)	7,152	6,850.5
Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(10.2)	(9.9)
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	$ 0	$ 250
Debt Instrument, Interest Rate, Stated Percentage	6.35%	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 August 15, 2028 [Member] [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 400	0
Debt Instrument, Interest Rate, Stated Percentage	3.80%
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%
Senior Notes [Member] | Series due August 15, 2047 [Member] [Domain] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	3.85%
Senior Notes [Member] | Series due April 1, 2047 [Member] | Og and E [Member]
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	4.15%
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	$ 9.6	9.7
Debt Instrument, Interest Rate, Stated Percentage	3.80%
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 CA_2

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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 September 1, 2018 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Sep. 1, 2018	Sep. 1, 2018
Debt Instrument, Interest Rate, Stated Percentage	6.35%	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 August 15, 2028 [Member] [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Aug. 15, 2028
Debt Instrument, Interest Rate, Stated Percentage	3.80%
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%
Senior Notes [Member] | Series due April 1, 2047 [Member] | OG&E [Member]
Debt Instrument, Maturity Date	Apr. 1, 2047
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Senior Notes [Member] | Series due August 15, 2047 [Member] [Domain] | OG&E [Member]
Debt Instrument, Maturity Date	Aug. 15, 2047
Debt Instrument, Interest Rate, Stated Percentage	3.85%
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	3.80%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.01%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.01%
Minimum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.03%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	2.00%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.83%
Maximum [Member] | Debentures Subject to Mandatory Redemption [Member] | Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument, Interest Rate, Stated Percentage	1.86%

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Common Stock, Shares, Outstanding		199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Balance at Dec. 31, 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 (Loss), Net of Tax, Number of Shares		0
Other comprehensive loss, net of tax	5.8	$ 0	0	0	5.8
Dividends declared on common stock		0
Dividends declared on common stock	(230.7)	$ 0	0	(230.7)	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		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)
Common Stock, Shares, Outstanding		199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income	22.3	$ 0	0	26.8	(4.5)
Comprehensive income (loss)
Net income	619	$ 0	0	619	0
Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification, Number of Shares		0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(4.5)
Other comprehensive loss, net of tax	10.6	$ 0	0	0	10.6
Dividends declared on common stock		0
Dividends declared on common stock	(253.6)	$ 0	0	(253.6)	0
Stock Issued During Period, Shares, New Issues		0
Expense of common stock	(0.1)	$ 0	(0.1)	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
Stock-based compensation	9.1	$ 0	9.1	0	0
Balance at Dec. 31, 2017	$ 3,851.1	$ 2	1,112.8	2,759.5	(23.2)
Common Stock, Shares, Outstanding	199.7	199.7
Net Income (Loss), Including portion attributable to noncontrolling interest, Number of Shares		0
Comprehensive income (loss)
Net income	$ 425.5	$ 0	0	425.5	0
Other Comprehensive Income (Loss), Net of Tax, Number of Shares		0
Other comprehensive loss, net of tax	(5.7)	$ 0	0	0	(5.7)
Dividends declared on common stock		0
Dividends declared on common stock	(278.7)	$ 0	0	(278.7)	0
Stock Issued During Period, Shares, New Issues		0
Expense of common stock	(0.1)	$ 0	(0.1)	0	0
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition, Number of Shares		0
Stock-based compensation	13	$ 0	13	0	0
Balance at Dec. 31, 2018	$ 4,005.1	$ 2	$ 1,125.7	$ 2,906.3	$ (28.9)
Common Stock, Shares, Outstanding	199.7	199.7

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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 a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas . Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable was formed in 2013 , and its general partner is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company accounts for its interest in Enable using the equity method of accounting. Enable is primarily engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns a crude oil gathering business in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama. 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, which 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 $1.7 million and $1.5 million at December 31, 2018 and 2017 , 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 at December 31, 2018 as presented in Note 13. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in the 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, 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 is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 7.6 percent , 8.2 percent and 8.2 percent for the years ended December 31, 2018 , 2017 and 2016 , respectively. 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. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Revenues from Contracts with Customers 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. Integrated Market and Transmission OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. Purchases and sales are based on the fixed transaction price determined by the market at the time of the purchase or sale and the MWh quantity purchased or sold. These results are reported as Revenues from Contracts with Customers or Cost of Sales in the Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP. OG&E's transmission revenues are generated by the use of OG&E's transmission network by the SPP, which operates the network, on behalf of other transmission owners. OG&E recognizes revenue on the sale of transmission service to its customers over time as the service is provided in the amount OG&E has a right to invoice. Transmission service to the SPP is billed monthly based on a fixed transaction price determined by OG&E's FERC-approved formula transmission rates along with other SPP-specific charges and the megawatt quantity reserved. Other Revenues Revenues from Alternative Revenue Programs Other Revenues on the Consolidated Statements of Income is comprised of certain rider revenue that includes alternative revenue measures as defined in ASC 980, "Regulated Operations," which details two types of alternative revenue programs. The first type adjusts billings for the effects of weather abnormalities or broad external factors or to compensate OG&E for demand-side management initiatives (i.e., no-growth plans and similar conservation efforts). The second type provides for additional billings (i.e., incentive awards) for the achievement of certain objectives, such as reducing costs, reaching specified milestones or demonstratively improving customer service. Once the specific events permitting billing of the additional revenues under either program type have been completed, OG&E recognizes the additional revenues if (i) the program is established by an order from OG&E's regulatory commission that allows for automatic adjustment of future rates; (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery; and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized. 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. 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.
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 the Company during 2017 and 2018 . All amounts below are presented net of tax. Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net Income Prior Service Cost (Credit) Net Income (Loss) Prior Service Cost (Credit) Total Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) Other comprehensive income (loss) before reclassifications 0.4 — (0.6 ) 6.3 6.1 Amounts reclassified from accumulated other comprehensive income (loss) 2.5 (0.1 ) — (0.6 ) 1.8 Cumulative effect of change in accounting principle (5.7 ) — (0.1 ) 1.3 (4.5 ) Settlement cost 2.2 — 0.5 — 2.7 Net current period other comprehensive income (0.6 ) (0.1 ) (0.2 ) 7.0 6.1 Balance at December 31, 2017 (32.7 ) — 2.5 7.0 (23.2 ) Other comprehensive income (loss) before reclassifications (14.1 ) — 2.1 — (12.0 ) Amounts reclassified from accumulated other comprehensive income (loss) 3.3 — — (1.7 ) 1.6 Settlement cost 4.7 — — — 4.7 Net current period other comprehensive income (loss) (6.1 ) — 2.1 (1.7 ) (5.7 ) Balance at December 31, 2018 $ (38.8 ) $ — $ 4.6 $ 5.3 $ (28.9 ) 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, 2018 and 2017 . Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Consolidated Statements of Income Year Ended December 31, (In millions) 2018 2017 Amortization of Pension Plan and Restoration of Retirement Income Plan items: Actuarial losses (A) $ (4.4 ) $ (3.9 ) Other Net Periodic Benefit Expense Prior service cost — 0.1 Other Net Periodic Benefit Expense Settlement cost (A) (6.3 ) (3.6 ) Other Net Periodic Benefit Expense (10.7 ) (7.4 ) Income Before Taxes (2.7 ) (2.8 ) Income Tax Expense (Benefit) $ (8.0 ) $ (4.6 ) Net Income Amortization of postretirement benefit plans items: Prior service cost $ 2.3 $ 0.9 Other Net Periodic Benefit Expense Settlement cost (A) — (0.7 ) Other Net Periodic Benefit Expense 2.3 0.2 Income Before Taxes 0.6 0.1 Income Tax Expense (Benefit) $ 1.7 $ 0.1 Net Income Total reclassifications for the period $ (6.3 ) $ (4.5 ) Net Income (A) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost (see Note 12 for additional information). The amounts in accumulated other comprehensive loss (gain) at December 31, 2018 that are expected to be recognized into earnings in 2019 are as follows: (In millions) Pension Plan and Restoration of Retirement Income Plan: Net gain $ (4.9 ) Postretirement Benefit Plans: Net loss 0.3 Prior service cost 2.3 Total, net of tax $ (2.3 )
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from two to 74 years. The following table summarizes changes to the Company's asset retirement obligations during the years ended December 31, 2018 and 2017 . (In millions) 2018 2017 Balance at January 1 $ 75.1 $ 69.6 Accretion expense 3.4 3.1 Revisions in estimated cash flows (A) 6.8 2.4 Liabilities settled (1.4 ) — Balance at December 31 $ 83.9 $ 75.1 (A) Assumptions changed related to the estimated timing and estimated cost of ash pond removal at one of OG&E's generating facilities. 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 $23.4 million and $17.1 million in accrued environmental liabilities at December 31, 2018 and 2017 , respectively, which are included in the Company's asset retirement obligations.
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, 2018 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 227.2 $ 78.2 $ 149.0 Redbud Plant (A)(B) 51 % $ 493.9 $ 145.3 $ 348.6 (A) Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million . December 31, 2017 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 226.8 $ 71.4 $ 155.4 Redbud Plant (A)(B) 51 % $ 496.6 $ 136.0 $ 360.6 (A) Construction work in progress was $0.4 million and $7.8 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million . The Company's property, plant and equipment and related accumulated depreciation are divided into the following major classes: December 31, 2018 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy: Property, plant and equipment $ 6.1 $ — $ 6.1 OGE Energy property, plant and equipment 6.1 — 6.1 OG&E: Distribution assets 4,229.4 1,324.5 2,904.9 Electric generation assets (A) 4,657.2 1,572.8 3,084.4 Transmission assets (B) 2,846.7 534.2 2,312.5 Intangible plant 187.6 135.1 52.5 Other property and equipment 444.2 160.8 283.4 OG&E property, plant and equipment 12,365.1 3,727.4 8,637.7 Total property, plant and equipment $ 12,371.2 $ 3,727.4 $ 8,643.8 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million . December 31, 2017 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy: Property, plant and equipment $ 6.1 $ — $ 6.1 OGE Energy property, plant and equipment 6.1 — 6.1 OG&E: Distribution assets 4,057.1 1,259.1 2,798.0 Electric generation assets (A) 4,475.0 1,493.5 2,981.5 Transmission assets (B) 2,767.7 506.5 2,261.2 Intangible plant 181.8 135.8 46.0 Other property and equipment 421.0 173.9 247.1 OG&E property, plant and equipment 11,902.6 3,568.8 8,333.8 Total property, plant and equipment $ 11,908.7 $ 3,568.8 $ 8,339.9 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million . OG&E's unamortized computer software costs, included in intangible plant above, were $44.3 million and $37.5 million at December 31, 2018 and 2017 , respectively. The following table summarizes the Company's amortization expense for computer software costs. Year Ended December 31 (In millions) 2018 2017 2016 OGE Energy $ — $ 0.2 $ 1.4 OG&E 9.6 8.8 8.0 Total $ 9.6 $ 9.0 $ 9.4 Depreciation and Amortization The provision for depreciation, which was 2.7 percent and 2.5 percent of the average depreciable utility plant for 2018 and 2017 , respectively, is calculated using the 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 2019 , the provision for depreciation is projected to be 2.7 percent of the average depreciable utility plant. Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2018 , 98.7 percent will be amortized over 10.4 years with the remaining 1.3 percent of the intangible plant balance at December 31, 2018 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.
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 $57.6 million and $84.3 million at December 31, 2018 and 2017 , 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 was 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 to be removed from storage over four years. As of December 31, 2018 , all cushion gas had been withdrawn from storage.
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: December 31 (In millions) 2018 2017 REGULATORY ASSETS Current: Production tax credit rider under recovery (A) $ 6.9 $ — Oklahoma demand program rider under recovery (A) 6.4 31.6 Fuel clause under recoveries 2.0 — SPP cost tracker under recovery (A) — 7.7 Other (A) 3.2 1.5 Total current regulatory assets $ 18.5 $ 40.8 Non-current: Benefit obligations regulatory asset $ 188.2 $ 177.2 Deferred storm expenses 36.5 42.2 Smart Grid 25.6 32.8 Unamortized loss on reacquired debt 11.4 12.3 Arkansas deferred pension expenses 6.8 5.1 Sooner Dry Scrubbers 4.5 — Other 12.8 13.4 Total non-current regulatory assets $ 285.8 $ 283.0 REGULATORY LIABILITIES Current: SPP cost tracker over recovery (B) $ 16.8 $ — Reserve for tax refund (B) 15.4 — Transmission cost recovery rider over recovery (B) 2.7 0.2 Fuel clause over recoveries 0.3 1.7 Other (B) 1.4 2.0 Total current regulatory liabilities $ 36.6 $ 3.9 Non-current: Income taxes refundable to customers, net $ 937.1 $ 955.5 Accrued removal obligations, net 308.1 288.4 Pension tracker 18.7 32.3 Other 6.8 7.2 Total non-current regulatory liabilities $ 1,270.7 $ 1,283.4 (A) Included in Other Current Assets on the Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Consolidated Balance Sheets. As discussed in Note 15 under "Oklahoma Rate Review Filing - January 2018," as a result of the settlement agreement reached in the most recent Oklahoma rate review, OG&E removed production tax credits from base rates and now utilizes a separate rider to credit customers for production tax credits, which can either result in a regulatory asset or regulatory liability based on the differential between estimated and actual production tax credits included in the rider. OG&E recovers program costs related to the Demand and Energy Efficiency Program in Oklahoma through the Demand Program Rider, which operates on a three year program cycle. The most recently concluded cycle allowed for recovery through December 2018 of energy efficiency program costs as well as associated lost revenues for achieved energy efficiency and demand savings and performance-based incentives. As discussed in Note 15 under "Demand Program Portfolio Filing," in December 2018, the OCC approved OG&E's 2019 through 2021 program cycle demand portfolio programs, which includes (i) energy efficiency 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. Fuel clause recoveries are generated from OG&E's customers when OG&E's cost of fuel either exceeds or is less than the amount billed to its customers. 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. 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 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: December 31 (In millions) 2018 2017 Pension Plan and Restoration of Retirement Income Plan: Net loss $ 185.3 $ 172.4 Postretirement Benefit Plans: Net loss 25.6 33.6 Prior service cost (22.7 ) (28.8 ) Total $ 188.2 $ 177.2 The following amounts in the benefit obligations regulatory asset at December 31, 2018 are expected to be recognized as components of net periodic benefit cost in 2019 : (In millions) Pension Plan and Restoration of Retirement Income Plan: Net loss $ 13.8 Postretirement Benefit Plans: Net loss 2.7 Prior service cost (6.1 ) Total $ 10.4 OG&E includes in expense any Oklahoma storm-related operation and maintenance expenses up to $2.7 million annually and defers to a regulatory asset 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. OG&E deferred to a regulatory asset the incremental and stranded costs that were accumulated during Smart Grid deployment, including (i) costs for web portal access, (ii) costs for education and home energy reports and (iii) stranded costs associated with OG&E's analog electric meters, which have been replaced by smart meters. These costs have been included in the Smart Grid asset in the table above, and as approved in recent rate reviews in Oklahoma and Arkansas, these costs are now being recovered over a six year period. 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 expense 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. Arkansas includes a certain level of pension expense in base rates. When the Pension Plan experiences a settlement, which represents an acceleration of future pension costs, OG&E defers to a regulatory asset the Arkansas jurisdictional portion of each settlement, which historically was recovered from customers over the average life of the remaining plan participants. A portion of these settlements is now being recovered in current rates, and additional amounts will be requested as additional settlements occur. For additional information related to settlements, see Note 12. As discussed in Note 15 under "Oklahoma Rate Review Filing - January 2018," as the result of a settlement agreement reached in the most recent Oklahoma rate review, OG&E began deferring the non-fuel incremental operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes for the Dry Scrubbers at Sooner Units 1 and 2 as a regulatory asset. Recovery of these costs was requested in OG&E's December 2018 rate review filing. For additional information on the Dry Scrubber project, see Note 15 under "Environmental Compliance Plan." OG&E recovers certain SPP costs related to base plan charges from its customers and refunds certain SPP revenues received to its customers in Oklahoma through the SPP cost tracker and in Arkansas through the transmission cost recovery rider. Further discussion of the Company's reserve for tax refund in response to OCC, APSC and FERC proceedings can be found in Notes 8 and 15. Income taxes refundable to customers, net, represents the reduction in accumulated deferred income taxes resulting from the reduction in the federal income tax rate as part of the 2017 Tax Act and includes income taxes recoverable from customers that represent income tax benefits previously used to reduce OG&E's revenues (treated as regulatory assets). These liabilities will be returned to customers in varying amounts over approximately 80 years, and the assets will be amortized over the estimated remaining life of the assets to which they relate, as the temporary differences that generated the income tax benefits turn around. Accrued removal obligations, net represents 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 reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker regulatory liability in the 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 or liabilities, which could have significant financial effects.
Reclassifications [Text Block]	Reclassifications Certain prior-year amounts have been reclassified to conform to the current year presentation. Amounts for the years ended December 31, 2017 and 2016 have been adjusted for the reclassification of net periodic benefit cost components and the regulatory Pension tracker mechanism between Other Operation and Maintenance and Other Net Periodic Benefit Expense in the Company's Consolidated Statements of Income to be consistent with the 2018 presentation due to the Company's adoption of ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." Further discussion can be found in Note 12.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2018
Accounting Pronouncement [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting Pronouncements Recently Adopted Accounting Standards Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)." The Company adopted this standard in the first quarter of 2018 utilizing the modified retrospective transition method and applied the new standard only to contracts that were not completed at the date of initial application. The Company determined it was not necessary to change the timing or amounts of revenue recognized based on the adoption of Topic 606. Therefore, financial statement amounts in the period of adoption have not changed under Topic 606 as compared with the guidance that was in effect before the adoption of Topic 606. The adoption did change financial statement presentation as Operating Revenues are now separated between Revenues from Contracts with Customers and Other Revenues in the 2018 Consolidated Statements of Income. In addition, gains and losses associated with OG&E's guaranteed flat bill program that were previously included in Net Other Income in the Consolidated Statements of Income are now presented as Revenues from Contracts with Customers since the gains and losses are included within the transaction price in the contract under Topic 606. Operating Revenues presented in the 2017 Consolidated Statements of Income did not change from prior year. Alternative revenue programs are scoped out of Topic 606, as these programs are considered agreements between an entity and a regulator, not contracts between an entity and a customer; therefore, the Company now presents revenues from alternative revenue programs separately from revenues from contracts with customers. Further discussion regarding the Company's revenue recognition as well as additional disclosures resulting from the adoption of Topic 606 can be found in Notes 1 and 3. Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets. In February 2017, the FASB issued ASU 2017-05, "Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets." ASC 610-20 was issued as part of ASU 2014-09 and was added to provide guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with non-customers. The new guidance clarifies the application of the guidance in Topic 606 for the derecognition of nonfinancial assets and unifies guidance related to partial sales of nonfinancial assets. The Company adopted the new guidance beginning in the first quarter of 2018, which did not have a material effect on its Consolidated Financial Statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, "Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost." The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit cost between those that are attributed to compensation for service and those that are not. The service cost component of benefit cost continues to be presented within operating income, but entities are now required to present the other components of benefit cost as non-operating within the income statement. Additionally, the new guidance only permits the capitalization of the service cost component of net benefit cost. The accounting change is required to be applied on a retrospective basis for the presentation of components of net benefit cost and on a prospective basis for the capitalization of only the service cost component of net benefit costs. The Company adopted the new guidance beginning in the first quarter of 2018. The presentation and recognition impacts of the Company's adoption of ASU 2017-07 are further discussed in Note 12. Recognition and Measurement of Financial Assets and Financial Liabilities. In January 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The new guidance, among other things, requires entities to measure equity instruments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) at fair value with changes in fair value recognized in net income. Further, an entity has the option to measure equity instruments that do not have readily determinable fair values at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investment of the same issuer. The Company adopted the new guidance beginning in the first quarter of 2018, which did not have a material effect on its Consolidated Financial Statements. Leases. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)." The main difference between prior lease accounting and Topic 842 is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under prior 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 for items such as initial direct costs. For income statement purposes, Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to prior capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in prior lease guidance but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition method and provides for certain practical expedients. Transition method options include application of the new guidance at the beginning of the earliest comparative period presented or at the adoption date, with a cumulative-effect adjustment to retained earnings in the period of adoption. The Company evaluated its current lease contracts and applied the package of practical expedients allowing entities to not reassess (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases and (iii) initial direct costs for any existing leases. The Company recognized approximately $38.0 million of lease liabilities in its Consolidated Balance Sheet at January 1, 2019 for railcar, wind farm land and office space leases. In January 2018, the FASB issued ASU 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842," which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate land easements under Topic 842 that exist or expired before the entity's adoption of Topic 842 and that were not previously accounted for as leases under ASC 840, "Leases." Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. ASU 2018-01 is effective for fiscal years beginning after December 2018. The Company elected this practical expedient during its adoption of Topic 842 and did not evaluate existing easement contracts under Topic 842, if these contracts had not previously been accounted for under Topic 840. In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842): Targeted Improvements," which provides the following additional amendments to ASU 2016-02: (i) entities can elect to initially apply ASU 2016-02 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and (ii) lessors can elect a practical expedient, by class of underlying asset, to account for nonlease components and the associated lease component as a single component, if the nonlease component otherwise would be accounted for under Topic 606 and certain conditions, as described in ASU 2018-11, are met. If an entity elects the additional (and optional) transition method, the entity will provide the required Topic 840 disclosures for all periods that continue to be reported under Topic 840. ASU 2018-11 is effective for fiscal years beginning after December 2018. The Company elected the transition method provided by the guidance allowing for initial application at January 1, 2019. Issued Accounting Standards Not Yet Adopted Fair Value Measurement Disclosure Framework. In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement." The new guidance removes, adds or modifies disclosure requirements that impact all levels of the fair value hierarchy, as well as investments measured using the net asset value practical expedient. ASU 2018-13 is effective for fiscal years beginning after December 2019 and is required to be applied both retrospectively and prospectively, depending on the specific disclosure change. Early adoption is permitted. The Company does not believe this ASU will have a significant impact on its financial statement disclosures. Defined Benefit Plans Disclosure Framework. In August 2018, the FASB issued ASU 2018-14, "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans." The new guidance removes, adds or clarifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. ASU 2018-14 is effective for fiscal years ending after December 2020 and is required to be applied on a retrospective basis. Early adoption is permitted. The Company does not believe this ASU will have a significant impact on its financial statement disclosures. Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. In August 2018, the FASB issued ASU 2018-15, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." The new guidance aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. ASU 2018-15 is effective for fiscal years beginning after December 2019 and can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its Consolidated Financial Statements.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenue Recognition The following table disaggregates the Company's revenues from contracts with customers by customer classification. The Company's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." (In millions) Year Ended Residential $ 877.8 Commercial 578.0 Industrial 191.1 Oilfield 150.2 Public authorities and street light 197.4 System sales revenues 1,994.5 Provision for rate refund (6.0 ) Integrated market 48.7 Transmission 147.4 Other 27.1 Revenues from contracts with customers $ 2,211.7

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliate and Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity Method Investments and Joint Ventures Disclosure [Text Block]	Investment in Unconsolidated Affiliate and Related Party Transactions In 2013, the Company, CenterPoint and the ArcLight group formed Enable as a private limited partnership, and the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and recorded the contribution at historical cost. The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings was allocated to the assets acquired and liabilities assumed based on their fair value. Enogex Holdings' assets, liabilities and equity were accordingly adjusted to estimated fair value, resulting in an increase to Enable's equity of $2.2 billion . Since the contribution of Enogex LLC to Enable was recorded at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable. At December 31, 2018 , the Company owned 111.0 million common units, or 25.6 percent , of Enable's outstanding common units. On December 31, 2018 , Enable's common unit price closed at $13.53. The Company recorded equity in earnings of unconsolidated affiliates of $152.8 million , $131.2 million and $101.8 million for the years ended December 31, 2018 , 2017 and 2016 , 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 original investment in Enogex LLC 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, beginning in 2013, 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 above. Summarized unaudited financial information for 100 percent of Enable is presented below as of December 31, 2018 and 2017 and for the years ended December 31, 2018 , 2017 and 2016 . Balance Sheet December 31, (In millions) 2018 2017 Current assets $ 449 $ 416 Non-current assets $ 11,995 $ 11,177 Current liabilities $ 1,615 $ 1,279 Non-current liabilities $ 3,211 $ 2,660 Income Statement Year Ended December 31, (In millions) 2018 2017 2016 Total revenues $ 3,431 $ 2,803 $ 2,272 Cost of natural gas and NGLs $ 1,819 $ 1,381 $ 1,017 Operating income $ 648 $ 528 $ 385 Net income $ 485 $ 400 $ 290 The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for the years ended December 31, 2018 , 2017 and 2016 , respectively. Year Ended December 31, (In millions) 2018 2017 2016 Enable net income $ 485.3 $ 400.3 $ 289.5 Distributions senior to limited partners — — (9.1 ) Differences due to timing of OGE Energy and Enable accounting close — — (12.2 ) Enable net income used to calculate OGE Energy's equity in earnings $ 485.3 $ 400.3 $ 268.2 OGE Energy's percent ownership at period end 25.6 % 25.7 % 25.7 % OGE Energy's portion of Enable net income $ 124.4 $ 102.7 $ 70.7 Impairments recognized by Enable associated with OGE Energy's basis difference — — 2.6 OGE Energy's share of Enable net income 124.4 102.7 73.3 Amortization of basis difference 11.2 11.3 11.6 Elimination of Enable fair value step up 17.2 17.2 16.9 Equity in earnings of unconsolidated affiliates $ 152.8 $ 131.2 $ 101.8 The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $680.3 million as of December 31, 2018 . The following table reconciles the basis difference in Enable from December 31, 2017 to December 31, 2018 . (In millions) Basis difference at December 31, 2017 $ 714.2 Change in Enable basis difference (5.5 ) Amortization of basis difference (11.2 ) Elimination of Enable fair value step up (17.2 ) Basis difference at December 31, 2018 $ 680.3 On February 8, 2019, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common units, which is unchanged from the previous quarter. If cash distributions to Enable's unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent , of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable's cash distributions at the time of the exercise of this reset election. Distributions received from Enable were $141.2 million , $141.2 million and $141.2 million during the years ended December 31, 2018 , 2017 and 2016 , respectively. Related Party Transactions - the Company and Enable The Company and Enable are currently parties to several agreements whereby the Company provides specified support services to Enable, such as certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $0.6 million , $2.3 million and $4.7 million for December 31, 2018 , 2017 and 2016 , respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and 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. Pursuant to a seconding agreement, the Company provides seconded employees to Enable to support Enable's operations. As of December 31, 2018 , 90 employees that participate in the Company's defined benefit and retirement plans are seconded to Enable. The Company billed Enable for reimbursement of $27.5 million , $29.5 million and $28.7 million in 2018 , 2017 and 2016 , respectively, under the Transitional Seconding Agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by $20.4 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 for amounts billed for transitional services, including the cost of seconded employees, of $1.7 million and $2.0 million as of December 31, 2018 and 2017 , respectively, which are included in Accounts Receivable on the Company's Consolidated Balance Sheets. Related Party Transactions - OG&E and Enable Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. In October 2018, OG&E and Enable agreed to a new contract that will be effective as of April 2019 for a five year period ending May 2024. 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 that became effective in December 2018 related to the project to convert Muskogee Units 4 and 5 from coal to natural gas. The following table summarizes related party transactions between OG&E and Enable during the years ended December 31, 2018 , 2017 and 2016 . Year Ended December 31, (In millions) 2018 2017 2016 Operating revenues: Electricity to power electric compression assets $ 16.3 $ 14.0 $ 11.5 Cost of sales: Natural gas transportation services $ 37.9 $ 35.0 $ 35.0 Natural gas (sales) purchases $ (3.2 ) $ (2.1 ) $ 11.2

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy are as follows: Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). The Company had no financial instruments measured at fair value on a recurring basis at December 31, 2018 and 2017 . The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt 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, 2018 and 2017 . 2018 2017 December 31 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year): Senior Notes $ 3,001.9 $ 3,178.2 $ 2,854.3 $ 3,242.8 OG&E Industrial Authority Bonds $ 135.4 $ 135.4 $ 135.4 $ 135.4 Tinker Debt $ 9.6 $ 8.7 $ 9.7 $ 9.8

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 related to the Company's performance units and restricted stock . Year Ended December 31 (In millions) 2018 2017 2016 Performance units: Total shareholder return $ 8.2 $ 7.6 $ 4.5 Earnings per share 5.1 1.4 — Total performance units 13.3 9.0 4.5 Restricted stock 0.1 0.1 0.1 Total compensation expense $ 13.4 $ 9.1 $ 4.6 Income tax benefit $ 3.4 $ 3.5 $ 1.8 The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units. In 2018 , 2017 and 2016 , there were 26,211 shares , 2,298 shares and 2,100 shares , respectively, of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock grants and payouts of earned performance units. 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 Company estimates expected forfeitures in accounting for performance unit compensation expense. 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 Sheets. 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 are accrued on a quarterly basis pending achievement of payout criteria and are 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. 2018 2017 2016 Number of units granted 261,916 260,570 284,211 Fair value of units granted $ 36.86 $ 41.77 $ 20.97 Expected dividend yield 3.6 % 3.8 % 3.5 % Expected price volatility 19.0 % 19.9 % 19.8 % Risk-free interest rate 2.38 % 1.44 % 0.88 % Expected life of units (in years) 2.86 2.80 2.84 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. 2018 2017 2016 Number of units granted 87,308 86,857 94,735 Fair value of units granted $ 31.03 $ 34.83 $ 26.64 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 primarily 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 will only be paid on restricted stock awards that vest; therefore, 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. 2018 2017 2016 Shares of restricted stock granted 826 3,145 1,881 Fair value of restricted stock granted $ 36.28 $ 34.96 $ 29.27 A summary of the activity for the Company's performance units and restricted stock at December 31, 2018 and changes in 2018 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 12/31/17 724,551 241,518 4,242 Granted 261,916 (A) 87,308 (A) 826 Converted (201,431 ) (B) $ — (67,148 ) (B) $ 1.2 N/A Vested N/A N/A (2,357 ) $ 0.1 Forfeited (29,556 ) (9,853 ) — Units/shares outstanding at 12/31/18 755,480 $ 53.2 251,825 $ 14.1 2,711 $ 0.1 Units/shares fully vested at 12/31/18 274,078 $ 19.8 91,356 $ 7.2 (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, 2017 which were settled in February 2018. A summary of the activity for the Company's non-vested performance units and restricted stock at December 31, 2018 and changes in 2018 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 12/31/17 523,120 $ 30.96 174,370 $ 30.58 4,242 $ 33.58 Granted 261,916 (A) $ 36.86 87,308 (A) $ 31.03 826 $ 36.28 Vested (274,078 ) $ 21.69 (91,356 ) $ 26.93 (2,357 ) $ 32.84 Forfeited (29,556 ) $ 35.55 (9,853 ) $ 31.94 — $ — Units/shares non-vested at 12/31/18 481,402 $ 39.17 160,469 $ 32.82 2,711 $ 35.00 Units/shares expected to vest 464,027 (B) 154,678 (B) 2,711 (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) The intrinsic value of the performance units based on total shareholder return and earnings per share is $32.0 million and $6.8 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) 2018 2017 2016 Performance units: Total shareholder return $ 5.9 $ 6.3 $ 6.4 Earnings per share $ 4.9 $ 1.2 $ — Restricted stock $ 0.1 $ 0.1 $ 0.1 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, 2018 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance units: Total shareholder return $ 9.0 1.65 Earnings per share 2.5 1.66 Total performance units 11.5 Restricted stock 0.1 1.94 Total unrecognized compensation cost $ 11.6

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2018
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. Cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds are also disclosed in the table. Year Ended December 31 (In millions) 2018 2017 2016 NON-CASH INVESTING AND FINANCING ACTIVITIES Power plant long-term service agreement $ (9.2 ) $ (2.6 ) $ 39.5 SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the period for: Interest (net of interest capitalized) (A) $ 153.8 $ 139.6 $ 141.9 Income taxes (net of income tax refunds) $ 2.8 $ (16.0 ) $ (5.9 ) (A) Net of interest capitalized of $11.7 million , $18.0 million and $7.5 million in 2018 , 2017 and 2016 , respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes 2017 Tax Act In December 2017, the 2017 Tax Act was signed into law, reducing the corporate federal tax rate from 35 percent to 21 percent for tax years beginning in 2018. ASC 740, "Income Taxes," requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized and settled. Entities subject to ASC 980, "Accounting for Regulated Entities," such as OG&E, are required to recognize a regulatory liability for the decrease in taxes payable for the change in tax rates that are expected to be returned to customers through future rates and to recognize a regulatory asset for the increase in taxes receivable for the change in tax rates that are expected to be recovered from customers through future rates. At December 31, 2017, as a result of remeasuring existing deferred taxes at the lower 21 percent tax rate, the Company reduced net deferred income tax liabilities and increased regulatory liabilities. As of December 31, 2018 , the Company's regulatory liability for income taxes refundable to customers, net was $1.022 billion , as a result of the change in the corporate federal tax rate. As a result of the 2017 Tax Act, in early January 2018: (i) the OCC ordered OG&E to record a reserve, including accrued interest, to reflect the reduced federal corporate tax rate, among other tax implications, on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings; (ii) the APSC ordered OG&E to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act until the resulting benefits, including carrying charges, are returned to customers; and (iii) through a Section 206 filing with the FERC, modifications were requested to be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act. Further discussion regarding OG&E's response to OCC, APSC and FERC proceedings, including reserves to revenue for each jurisdiction, can be found in Note 15 under "Oklahoma Rate Review Filing - January 2018," "APSC Order - 2017 Tax Act," "FERC - Request for Waiver" and "FERC - Section 206 Filing." As of December 31, 2018 , the total recorded reserve was $15.4 million , which is included in Other Current Liabilities in the Company's Consolidated Balance Sheets. Staff Accounting Bulletin No. 118 Staff Accounting Bulletin No. 118 addresses the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the 2017 Tax Act. The Company recognized the provisional tax impacts related to the revaluation of deferred tax assets and liabilities as of December 31, 2017 , as the Company had not completed its accounting for income tax effects of the 2017 Tax Act. As of December 31, 2018, the Company has completed its accounting for the enactment-date income tax effects of the 2017 Tax Act. Upon further analysis of certain aspects of the 2017 Tax Act and refinement of the final calculations during the 12 months ended December 31, 2018, the Company adjusted its provisional amount by an increase to tax expense of $2.1 million and increased regulatory liabilities by $7.4 million . Income Tax Expense (Benefit) The items comprising income tax expense (benefit) are as follows: Year Ended December 31 (In millions) 2018 2017 2016 Provision (benefit) for current income taxes: Federal $ (1.9 ) $ 4.9 $ — State (4.4 ) (4.2 ) (5.7 ) Total provision (benefit) for current income taxes (6.3 ) 0.7 (5.7 ) Provision (benefit) for deferred income taxes, net: Federal 74.7 (75.9 ) 126.0 State 3.7 26.0 28.0 Total provision (benefit) for deferred income taxes, net 78.4 (49.9 ) 154.0 Deferred federal investment tax credits, net 0.1 (0.1 ) (0.2 ) Total income tax expense (benefit) $ 72.2 $ (49.3 ) $ 148.1 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 2015 or state and local tax examinations by tax authorities for years prior to 2014 . 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 2018 2017 2016 Statutory federal tax rate 21.0 % 35.0 % 35.0 % Federal deferred tax revaluation 0.4 (41.2 ) — Other 0.4 (0.1 ) 0.1 State income taxes, net of federal income tax benefit 0.4 2.0 1.9 Executive compensation limitation 0.2 — — Federal renewable energy credit (A) (5.1 ) (4.8 ) (6.8 ) Amortization of net unfunded deferred taxes (2.1 ) 0.7 0.7 Remeasurement of state deferred tax liabilities (0.4 ) 0.4 0.9 401(k) dividends (0.3 ) (0.5 ) (0.6 ) Federal investment tax credits, net — (0.1 ) (0.8 ) Uncertain tax positions — — 0.1 Effective income tax rate 14.5 % (8.6 )% 30.5 % (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, 2018 and 2017 were as follows: December 31 (In millions) 2018 2017 Deferred income tax liabilities, net: Accelerated depreciation and other property related differences $ 1,605.3 $ 1,449.6 Investment in Enable 469.9 441.7 Regulatory assets 17.4 18.9 Company Pension Plan 7.6 11.5 Bond redemption-unamortized costs 2.4 2.6 Derivative instruments 1.7 1.6 Other 1.1 (0.9 ) Income taxes recoverable from customers, net (239.6 ) (244.3 ) Federal tax credits (237.8 ) (218.5 ) State tax credits (156.0 ) (141.7 ) Regulatory liabilities (78.8 ) (16.8 ) Postretirement medical and life insurance benefits (23.6 ) (25.2 ) Asset retirement obligations (21.5 ) (19.2 ) Net operating losses (20.2 ) (21.1 ) Accrued liabilities (12.5 ) (7.4 ) Accrued vacation (2.3 ) (2.1 ) Deferred federal investment tax credits (1.8 ) (0.5 ) Uncollectible accounts (0.4 ) (0.4 ) Total deferred income tax liabilities, net $ 1,310.9 $ 1,227.8 As of December 31, 2018 , the Company has classified $16.4 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, 2018 , 2017 and 2016 . (In millions) 2018 2017 2016 Balance at January 1 $ 20.7 $ 20.7 $ 20.2 Tax positions related to current year: Additions — — 0.5 Balance at December 31 $ 20.7 $ 20.7 $ 20.7 As of December 31, 2018 , 2017 and 2016 , there were $16.4 million , $16.4 million and $13.5 million of unrecognized tax benefits that, if recognized, would affect the annual effective tax rate. Where applicable, the Company classifies income tax-related interest and penalties as interest expense and other expense, respectively. During the year ended December 31, 2018 , there were no income tax-related interest or penalties recorded with regard to uncertain tax positions. 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 2017, when the remaining federal net operating loss was utilized. State operating losses are being carried forward for utilization in future years. 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 remaining losses and credits before they begin to expire. The following table summarizes these carry forwards: (In millions) Carry Forward Amount Deferred Tax Asset Earliest Expiration Date State operating loss $ 451.8 $ 20.2 2030 Federal tax credits $ 237.8 $ 237.8 2032 State tax credits: Oklahoma investment tax credits $ 161.6 $ 127.7 N/A Oklahoma capital investment board credits $ 8.9 $ 8.9 N/A Oklahoma zero emission tax credits $ 24.1 $ 19.4 2020 N/A - not applicable

Common Equity

Common Equity	12 Months Ended
	Dec. 31, 2018
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 2018 . The Company may, from time to time, issue shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At December 31, 2018 , 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) 2018 2017 2016 Net income $ 425.5 $ 619.0 $ 338.2 Average common shares outstanding: Basic average common shares outstanding 199.7 199.7 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.8 0.3 0.2 Diluted average common shares outstanding 200.5 200.0 199.9 Basic earnings per average common share $ 2.13 $ 3.10 $ 1.69 Diluted earnings per average common share $ 2.12 $ 3.10 $ 1.69 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. Before the Company can pay any dividends on its common stock, the holders of any of its preferred stock that may be outstanding are entitled to receive their dividends at the respective rates as may be provided for the shares of their series. 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. 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 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 $580.5 million of the Company's retained earnings from being paid out in dividends. Accordingly, approximately $2.3 billion of the Company's retained earnings as of December 31, 2018 are unrestricted for the payment of dividends. 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 $674.9 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, 2018 are unrestricted for the payment of dividends.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
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, 2018 , the Company was in compliance with all of its debt agreements. OG&E Industrial Authority Bonds OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows: SERIES DATE DUE AMOUNT (In millions) 1.01% - 2.00% Garfield Industrial Authority, January 1, 2025 $ 47.0 1.01% - 1.83% Muskogee Industrial Authority, January 1, 2025 32.4 1.03% - 1.86% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4 All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as Long-Term Debt in the Company's 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 $250.1 million , $0.1 million , $0.1 million , $0.1 million and $0.1 million in 2019 , 2020 , 2021 , 2022 and 2023 , 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 are classified as Long-Term Debt in the Consolidated Balance Sheets and are being amortized over the life of the respective debt. Issuance of Long-Term Debt In August 2018, OG&E issued $400.0 million of 3.80 percent senior notes due August 15, 2028 . The proceeds from the issuance were added to OG&E's general funds to be used for general corporate purposes, including to fund the payment of OG&E's $250.0 million of 6.35 percent senior notes that matured on September 1, 2018 , to repay short-term debt and to fund ongoing capital expenditures and working capital .

Short-Term Debt and Credit Faci

Short-Term Debt and Credit Facilities	12 Months Ended
	Dec. 31, 2018
Short-term Debt [Abstract]
Short-Term Debt and Credit Facilities	Short-Term Debt and Credit Facilities The Company and OG&E's credit facilities each have a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent , as defined in each such facility. The Company and OG&E's facilities each also contain covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods. 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, 2018 , the Company had no short-term debt outstanding compared to $168.4 million at December 31, 2017 . The following table provides information regarding the Company's revolving credit agreements at December 31, 2018 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ — — % (D) March 8, 2023 (E) OG&E (C) 450.0 0.3 1.05 % (D) March 8, 2023 (E) Total $ 900.0 $ 0.3 1.05 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2018 . (B) This bank facility is available to back up the Company's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit. (E) In March 2017, the Company and OG&E entered into unsecured five-year revolving credit agreements totaling $900.0 million ( $450.0 million for the Company and $450.0 million for OG&E). Each of the facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. Effective March 9, 2018, the Company and OG&E utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023. The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit 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, 2019 and ending December 31, 2020.

Retirement Plans and Postretire

Retirement Plans and Postretirement Benefit Plans	12 Months Ended
	Dec. 31, 2018
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. The Company made a $15.0 million and $20.0 million contribution to its Pension Plan in 2018 and 2017 , respectively. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2019 . Any contribution to the Pension Plan during 2019 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 2018 and 2017, 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 plan settlement charges of $26.1 million during 2018 and $15.3 million during 2017. 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. During 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. 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 2018 and 2017 . 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, 2018 was $561.9 million and $7.8 million , respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2017 was $ 626.9 million and $ 7.5 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 included in the following table. Pension Plan Restoration of Retirement Postretirement December 31 (In millions) 2018 2017 2018 2017 2018 2017 Change in benefit obligation Beginning obligations $ 687.5 $ 672.2 $ 8.1 $ 7.0 $ 149.4 $ 215.9 Service cost 14.9 15.5 0.4 0.3 0.3 0.6 Interest cost 23.8 26.2 0.3 0.3 5.4 7.2 Plan settlements (73.7 ) (50.2 ) (2.0 ) — — (28.1 ) Plan amendments — — — — — (39.6 ) Participants' contributions — — — — 3.8 3.5 Actuarial losses (gains) (22.0 ) 38.6 2.8 0.7 (9.6 ) 5.6 Benefits paid (14.6 ) (14.8 ) — (0.2 ) (13.5 ) (15.7 ) Ending obligations $ 615.9 $ 687.5 $ 9.6 $ 8.1 $ 135.8 $ 149.4 Change in plans' assets Beginning fair value $ 635.3 $ 595.9 $ — $ — $ 50.2 $ 53.1 Actual return on plans' assets (39.2 ) 84.4 — — (0.6 ) 2.8 Employer contributions 15.0 20.0 2.0 0.2 5.4 34.6 Plan settlements (73.7 ) (50.2 ) (2.0 ) — — (28.1 ) Participants' contributions — — — — 3.8 3.5 Benefits paid (14.6 ) (14.8 ) — (0.2 ) (13.5 ) (15.7 ) Ending fair value $ 522.8 $ 635.3 $ — $ — $ 45.3 $ 50.2 Funded status at end of year $ (93.1 ) $ (52.2 ) $ (9.6 ) $ (8.1 ) $ (90.5 ) $ (99.2 ) Net Periodic Benefit Cost The Company adopted ASU 2017-07 in the first quarter of 2018 and, as a result, presents the service cost component of net benefit cost in operating income and the other components of net benefit cost as non-operating within its Consolidated Statements of Income. Further, as required by ASU 2017-07, the Company adjusted prior year income statement presentation of the net benefit cost components, which were previously presented in total within Other Operation and Maintenance in the Company's Consolidated Statements of Income. The Company elected the practical expedient allowed by ASU 2017-07 to utilize amounts disclosed in the Company's r etirement plans and postretirement benefit plans note for the prior comparative period as the estimation basis for applying the retrospective presentation requirements. The following table presents the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Consolidated Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in the Company's Consolidated Statements of Income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Expense in the Company's Consolidated Statements of Income. Pension Plan Restoration of Retirement Postretirement Benefit Plans Year Ended December 31 (In millions) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Service cost $ 14.9 $ 15.5 $ 15.8 $ 0.4 $ 0.3 $ 0.3 $ 0.3 $ 0.6 $ 0.8 Interest cost 23.8 26.2 25.5 0.3 0.3 0.4 5.4 7.2 9.5 Expected return on plan assets (44.1 ) (42.6 ) (41.5 ) — — — (2.0 ) (2.2 ) (2.3 ) Amortization of net loss 16.2 17.4 16.5 0.7 0.4 0.7 3.8 2.0 2.6 Amortization of unrecognized prior service cost (A) — (0.1 ) (0.1 ) 0.1 0.1 0.1 (8.4 ) (3.5 ) (8.8 ) Settlement cost 25.1 15.3 — 1.0 — 8.6 — 0.6 — Total net periodic benefit cost 35.9 31.7 16.2 2.5 1.1 10.1 (0.9 ) 4.7 1.8 Less: Amount paid by unconsolidated affiliates 2.5 4.3 5.1 0.1 — 0.3 (0.5 ) 0.3 0.2 Net periodic benefit cost (B) $ 33.4 $ 27.4 $ 11.1 $ 2.4 $ 1.1 $ 9.8 $ (0.4 ) $ 4.4 $ 1.6 (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 $35.4 million , $32.9 million and $22.5 million of net periodic benefit cost recognized in 2018 , 2017 and 2016 , respectively, OG&E recognized the following: • a change in pension expense in 2018 , 2017 and 2016 of $(14.1) million , $(2.3) million and $9.9 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1); • an increase in postretirement medical expense in 2018 , 2017 and 2016 of $4.4 million , $6.2 million and $7.9 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and • a deferral of pension expense in 2018, 2017 and 2016 of $2.1 million , $1.1 million and $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $26.1 million , $15.3 million and $8.6 million , respectively, which are included in the Arkansas deferred pension expense regulatory asset (see Note 1). As required by ASU 2017-07, the Company only capitalizes the service cost component of net benefit cost, beginning in the first quarter of 2018. Prior year capitalized amounts were not adjusted, as this change was implemented on a prospective basis. (In millions) 2018 2017 2016 Capitalized portion of net periodic pension benefit cost $ 3.8 $ 4.4 $ 4.0 Capitalized portion of net periodic postretirement benefit cost $ 0.2 $ 1.2 $ 0.8 Rate Assumptions Pension Plan and Postretirement Year Ended December 31 2018 2017 2016 2018 2017 2016 Assumptions to determine benefit obligations: Discount rate 4.20 % 3.60 % 4.00 % 4.30 % 3.70 % 4.20 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A 4.20 % Assumptions to determine net periodic benefit cost: Discount rate 3.73 % 4.00 % 4.00 % 3.70 % 4.20 % 4.25 % Expected return on plan assets 7.50 % 7.50 % 7.50 % 4.00 % 4.00 % 4.00 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A 4.20 % 4.20 % N/A - not applicable The discount rate used to compute the present value of plan liabilities is based generally on rates of high-grade corporate bonds with maturities similar to the average period over which benefits will be paid. The discount rate used to determine net benefit cost for the current year is the same discount rate used to determine the benefit obligation as of the previous year's balance sheet date. The overall expected rate of return on plan assets assumption was 7.50 percent in both 2018 and 2017 , 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 7.25 percent in 2019 with the rates trending downward to 4.50 percent by 2030 . 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) 2018 2017 2016 Effect on aggregate of the service and interest cost components $ — $ — $ — Effect on accumulated postretirement benefit obligations $ 0.1 $ 0.1 $ 0.2 ONE-PERCENTAGE POINT DECREASE Year Ended December 31 (In millions) 2018 2017 2016 Effect on aggregate of the service and interest cost components $ — $ — $ — Effect on accumulated postretirement benefit obligations $ 0.3 $ 0.3 $ 0.7 Pension 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 International ACWI ex-U.S. The fixed income managers are expected to use discretion over the asset mix of the trust assets in their 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 Service, S&P's Global Ratings 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-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-U.S. Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the U.S. 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 Plan Investments The following tables summarize the Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2018 and 2017 . There were no Level 3 investments held by the Pension Plan at December 31, 2018 and 2017 . (In millions) December 31, 2018 Level 1 Level 2 Net Asset Value (A) Common stocks $ 169.3 $ 169.3 $ — $ — U.S. Treasury notes and bonds (B) 137.9 137.9 — — Mortgage- and asset-backed securities 65.9 — 65.9 — Corporate fixed income and other securities 143.2 — 143.2 — Commingled fund (C) 19.7 — — 19.7 Foreign government bonds 4.4 — 4.4 — U.S. municipal bonds 0.6 — 0.6 — Money market fund 0.3 — — 0.3 Mutual fund 8.0 8.0 — — Futures: U.S. Treasury futures (receivable) 27.0 — 27.0 — U.S. Treasury futures (payable) (20.4 ) — (20.4 ) — Cash collateral 0.7 0.7 — — Forward contracts: Receivable (foreign currency) 0.1 — 0.1 — Total Pension Plan investments $ 556.7 $ 315.9 $ 220.8 $ 20.0 Receivable from broker for securities sold — Interest and dividends receivable 3.0 Payable to broker for securities purchased (36.9 ) Total Pension Plan assets $ 522.8 (A) GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy. (B) This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher. (C) This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets. (In millions) December 31, 2017 Level 1 Level 2 Net Asset Value (A) Common stocks $ 225.9 $ 225.9 $ — $ — U.S. Treasury notes and bonds (B) 169.7 169.7 — — Mortgage- and asset-backed securities 43.4 — 43.4 — Corporate fixed income and other securities 153.8 — 153.8 — Commingled fund (C) 29.9 — — 29.9 Foreign government bonds 4.0 — 4.0 — U.S. municipal bonds 1.2 — 1.2 — Money market fund 4.3 — — 4.3 Mutual fund 7.8 7.8 — — Futures: U.S. Treasury futures (receivable) 13.4 — 13.4 — U.S. Treasury futures (payable) (11.4 ) — (11.4 ) — Cash collateral 0.3 0.3 — — Forward contracts: Receivable (foreign currency) 0.1 — 0.1 — Total Pension Plan investments $ 642.4 $ 403.7 $ 204.5 $ 34.2 Receivable from broker for securities sold — Interest and dividends receivable 3.2 Payable to broker for securities purchased (10.3 ) Total Pension Plan assets $ 635.3 (A) GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy. (B) This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher. (C) 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 stocks, U.S. Treasury notes and bonds, mutual funds and cash collateral. 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 mortgage- and asset-backed securities, corporate fixed income and other securities, foreign government bonds, U.S. municipal bonds, U.S. 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. Postretirement Plans Investments The following tables summarize the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2018 and 2017 . There were no Level 2 investments held by the postretirement benefit plans at December 31, 2018 and 2017 . (In millions) December 31, 2018 Level 1 Level 3 Group retiree medical insurance contract $ 36.0 $ — $ 36.0 Mutual funds 8.9 8.9 — Cash 0.9 0.9 — Total plan investments $ 45.8 $ 9.8 $ 36.0 (In millions) December 31, 2017 Level 1 Level 3 Group retiree medical insurance contract $ 40.2 $ — $ 40.2 Mutual funds 9.5 9.5 — Cash 0.5 0.5 — Total plan investments $ 50.2 $ 10.0 $ 40.2 The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. 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) 2018 Group retiree medical insurance contract: Beginning balance $ 40.2 Interest income 0.7 Dividend income 0.5 Claims paid (4.6 ) Net unrealized losses related to instruments held at the reporting date (0.5 ) Realized losses (0.2 ) Investment fees (0.1 ) Ending balance $ 36.0 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 2019 $ 11.6 2020 $ 11.6 2021 $ 11.6 2022 $ 11.6 2023 $ 10.2 After 2023 $ 46.7 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 2019 $ 64.3 2020 $ 60.2 2021 $ 60.6 2022 $ 59.7 2023 $ 59.7 After 2023 $ 267.6 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 $1.9 million and $2.5 million at December 31, 2018 and 2017 , respectively. 401(k) Plan The Company provides a 401(k) Plan, and 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 reached 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 their 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

Report of Business Segments

Report of Business Segments	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 . 2018 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 2,270.3 $ — $ — $ — $ 2,270.3 Cost of sales 892.5 — — — 892.5 Other operation and maintenance 473.8 1.4 (0.6 ) — 474.6 Depreciation and amortization 321.6 — — — 321.6 Taxes other than income 88.2 0.6 3.2 — 92.0 Operating income (loss) 494.2 (2.0 ) (2.6 ) — 489.6 Equity in earnings of unconsolidated affiliates — 152.8 — — 152.8 Other income (expense) 25.6 (4.9 ) (3.4 ) (6.0 ) 11.3 Interest expense 151.8 — 10.2 (6.0 ) 156.0 Income tax expense (benefit) 40.0 37.1 (4.9 ) — 72.2 Net income (loss) $ 328.0 $ 108.8 $ (11.3 ) $ — $ 425.5 Investment in unconsolidated affiliates $ — $ 1,166.6 $ 10.9 $ — $ 1,177.5 Total assets $ 9,704.5 $ 1,169.8 $ 184.8 $ (310.5 ) $ 10,748.6 Capital expenditures $ 573.6 $ — $ — $ — $ 573.6 2017 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 2,261.1 $ — $ — $ — $ 2,261.1 Cost of sales 897.6 — — — 897.6 Other operation and maintenance 469.8 (0.8 ) (10.3 ) — 458.7 Depreciation and amortization 280.9 — 2.6 — 283.5 Taxes other than income 84.8 1.0 3.6 — 89.4 Operating income (loss) 528.0 (0.2 ) 4.1 — 531.9 Equity in earnings of unconsolidated affiliates — 131.2 — — 131.2 Other income (expense) 57.7 (1.0 ) (5.4 ) (0.9 ) 50.4 Interest expense 138.4 — 6.3 (0.9 ) 143.8 Income tax expense (benefit) (A) 141.8 (195.2 ) 4.1 — (49.3 ) Net income (loss) $ 305.5 $ 325.2 $ (11.7 ) $ — $ 619.0 Investment in unconsolidated affiliates $ — $ 1,151.9 $ 8.5 $ — $ 1,160.4 Total assets $ 9,255.6 $ 1,155.3 $ 109.1 $ (107.3 ) $ 10,412.7 Capital expenditures $ 824.1 $ — $ — $ — $ 824.1 (A) The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act. See Note 8 for further discussion of the effects of the 2017 Tax Act. 2016 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 2,259.2 $ — $ — $ — $ 2,259.2 Cost of sales 880.1 — — — 880.1 Other operation and maintenance 451.2 (0.1 ) (13.0 ) — 438.1 Depreciation and amortization 316.4 — 6.2 — 322.6 Taxes other than income 84.0 — 3.6 — 87.6 Operating income 527.5 0.1 3.2 — 530.8 Equity in earnings of unconsolidated affiliates — 101.8 — — 101.8 Other income (expense) 9.1 (7.7 ) (5.4 ) (0.2 ) (4.2 ) 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

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
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 office space lease. Future minimum payments for noncancellable operating leases are as follows: Year Ended December 31 (In millions) 2019 2020 2021 2022 2023 After 2023 Total Operating lease obligations: Railcars $ 18.6 $ — $ — $ — $ — $ — $ 18.6 Wind farm land leases 2.5 2.9 2.9 2.9 2.9 37.6 51.7 Office space lease 1.0 1.0 0.6 — — — 2.6 Total operating lease obligations $ 22.1 $ 3.9 $ 3.5 $ 2.9 $ 2.9 $ 37.6 $ 72.9 Payments for operating lease obligations were $4.9 million , $6.2 million and $9.3 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. OG&E Railcar Lease Agreement As of December 31, 2018, OG&E has a noncancellable operating lease with a purchase option, covering 1,093 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. At the end of the lease term, which was February 1, 2019, OG&E had the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chose not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars was less than the stipulated fair market value, OG&E would have been responsible for the difference in those values up to a maximum of $16.2 million . OG&E was also required to maintain all of the railcars it had under the operating lease. On February 1, 2019, OG&E renewed the lease agreement effective February 1, 2019, under similar terms and conditions, for a fleet of 780 railcars, expiring February 1, 2024. The number of railcars was reduced due to the conversion of Muskogee Units 4 and 5 to natural gas. At the end of the lease term, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $6.8 million . The railcar lease effective February 1, 2019 is not included in the operating lease obligations table above. 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. Office Space Lease In August 2012, the Company executed a noncancellable lease agreement for office space from September 1, 2013 to August 31, 2018. This lease had rent escalations which increased after five years and allowed for leasehold improvements. In February 2018, the Company executed a noncancellable lease agreement for office space from September 1, 2018 to August 31, 2021. This lease 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) 2019 2020 2021 2022 2023 Total Other purchase obligations and commitments: Cogeneration capacity and fixed operation and maintenance payments (A) $ 10.9 $ — $ — $ — $ — $ 10.9 Expected cogeneration energy payments (A) 2.4 — — — — 2.4 Minimum purchase commitments 75.8 44.6 44.6 44.6 44.6 254.2 Expected wind purchase commitments 56.3 56.9 57.1 57.5 58.0 285.8 Long-term service agreement commitments 46.8 2.4 2.4 2.4 14.4 68.4 Environmental compliance plan expenditures 5.8 0.2 — — — 6.0 Total other purchase obligations and commitments $ 198.0 $ 104.1 $ 104.1 $ 104.5 $ 117.0 $ 627.7 (A) Cogeneration capacity, fixed operation and maintenance and energy payments will end in 2019, as a result of contract expiration. As described below, OG&E intends to acquire the AES and Oklahoma Cogeneration LLC power plants, pending regulatory approval. Public Utility Regulatory Policy Act of 1978 At December 31, 2018 , OG&E has a QF contract with Oklahoma Cogeneration LLC which expires on August 31, 2019 and a QF contract with AES which expired on January 15, 2019. 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, and 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 QF contract and the 120 MWs Oklahoma Cogeneration LLC QF contract, OG&E purchases 100 percent of the electricity generated by the QFs. As part of the QF contract with AES, OG&E had the option to provide notice to AES to terminate the contract, and on August 24, 2018, OG&E notified AES that OG&E was exercising this option to terminate the contract, effective January 15, 2019. OG&E subsequently issued a request for proposals to fill the capacity need created by the termination of this QF contract. On December 20, 2018, OG&E announced its plan to acquire power plants from AES and Oklahoma Cogeneration LLC, pending regulatory approval, to meet customers' energy needs. Further discussion can be found in Note 15. For the years ended December 31, 2018 , 2017 and 2016 , OG&E made total payments to cogenerators of $112.4 million , $115.2 million and $124.8 million , respectively, of which $60.0 million , $63.0 million and $66.3 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 Purchase Commitments OG&E has coal contracts for purchases through March 31, 2019, whereby OG&E has the right but not the obligation to purchase a defined quantity of coal. OG&E purchases its coal through spot purchases on an as-needed basis. As a participant in the SPP Integrated Marketplace, OG&E purchases its natural gas supply through short-term agreements. OG&E relies on a combination of natural gas call 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 has natural gas transportation service contracts with Enable and ONEOK, Inc. The contract with Enable expires in April 2019, and in October 2018, OG&E and Enable agreed to a new contract that will be effective as of April 2019 for a five year period ending May 2024. The contracts with ONEOK, Inc. end in March 2019 and August 2037. These transportation contracts grant Enable and ONEOK, Inc. the responsibility of delivering natural gas to OG&E's generating facilities. OG&E Wind Purchase Commitments OG&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms. OG&E's current wind power portfolio also includes purchased power contracts as listed in the table below. Company Location Original Term of Contract Expiration of Contract MWs CPV Keenan Woodward County, OK 20 years 2030 152.0 Edison Mission Energy Dewey County, OK 20 years 2031 130.0 NextEra Energy Blackwell, OK 20 years 2032 60.0 The following table summarizes OG&E's wind power purchases for the years ended December 31, 2018 , 2017 and 2016 . Year Ended December 31 (In millions) 2018 2017 2016 CPV Keenan $ 27.0 $ 29.0 $ 29.2 Edison Mission Energy 21.7 22.1 21.1 NextEra Energy 6.8 7.4 7.3 FPL Energy (A) 2.1 2.6 3.4 Total wind power purchased $ 57.6 $ 61.1 $ 61.0 (A) OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018. 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 Long-Term Service Agreement 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 2031. 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 2029. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used. Environmental Laws and Regulations The activities of the Company 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 the Company's business activities in many ways, including the handling or disposal of waste material, planning for future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. Management believes that all of its operations are in substantial compliance with current federal, state and local environmental standards. Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. Air Quality Control System The Dry Scrubber system on Sooner Unit 1 completed certain emission testing in October 2018 and was placed into service. The Dry Scrubber system on Sooner Unit 2 completed certain emission testing in January 2019 and was placed into service. More detail regarding the ECP can be found under "Pending Regulatory Matters" in Note 15. 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. However, the rule was challenged in court when it was issued, and the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan on February 9, 2016 pending resolution of the court challenges. The EPA published a proposal on October 16, 2017 to repeal the Clean Power Plan. On August 31, 2018, without acting on the proposed repeal of the Clean Power Plan, the EPA published a proposed rule to replace the Clean Power Plan. The ultimate timing and impact of these standards on OG&E's operations cannot be determined with certainty at this time, although a requirement for significant reduction of CO 2 emissions from existing fossil-fuel-fired power plants ultimately could result in significant additional compliance costs that would affect the Company's future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. 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, 2018
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 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 2018 , 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 Oklahoma Rate Review Filing - January 2018 On January 16, 2018, OG&E filed a general rate review in Oklahoma, requesting a rate increase of $1.9 million per year, assuming a 9.9 percent return on equity. The filing sought recovery of the seven combustion turbines that are part of the Mustang Modernization Plan, an increase in depreciation rates to levels similar with rates in existence prior to the March 2017 OCC rate order and credit to customers for the impacts of the 2017 Tax Act, which was enacted on December 22, 2017. On December 22, 2017, the Attorney General of Oklahoma requested that the OCC reduce the rates and charges for electric service and provide for an immediate refund due to the customers of OG&E resulting from the 2017 Tax Act. In response, on January 4, 2018, the OCC ordered OG&E to record a reserve, beginning on January 4, 2018, to reflect the reduced federal corporate tax rate of 21 percent and the amortization of excess accumulated deferred income tax and any other tax implications of the 2017 Tax Act on an interim basis, subject to refund until utility rates were adjusted to reflect the federal tax savings and a final order was issued in the rate review. Further, the OCC ordered the amounts of any refunds of such reserves owed to customers should accrue interest at a rate equivalent to OG&E's cost of capital as previously recognized in the March 2017 OCC rate order. OG&E reserved the excess income taxes collected in current rates and any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus interest, from January 2018 through June 2018. On June 19, 2018, the OCC approved a Joint Stipulation and Settlement Agreement. Key terms of the settlement include the following: • an annual net decrease of $64.0 million in OG&E's rates to its Oklahoma retail customers, which reflects recovery of the Mustang Modernization Plan, offset by reductions for the impact of the lower corporate income taxes resulting from the 2017 Tax Act; • for purposes of calculating the Allowance for Funds Used During Construction and OG&E's various recovery riders that include a full return component, use of the most-recently approved return on equity of 9.5 percent and a capital structure of 47 percent debt/ 53 percent equity; • depreciation rates remain unchanged from the current depreciation rates approved in the March 2017 OCC rate order; • regulatory asset treatment for the Dry Scrubbers at Sooner Units 1 and 2 that will defer the non-fuel operation and maintenance expenses, depreciation, debt cost associated with the capital investment and related ad valorem taxes, subject to a prudence review in a future general rate review and a determination as to whether the project is used and useful; • production tax credits will be removed from base rates and placed into a separate rider; • a federal tax credit rider will be established to refund to customers the amount of excess taxes received from January to June 2018, as discussed above, and the ongoing annual true up of excess accumulated deferred income taxes resulting from the reduction in corporate income tax rates as part of the 2017 Tax Act (further discussed in Note 8); and • the demand program rider tariff will be revised to allow for concurrent recovery of lost revenues from foregone sales due to certain achieved energy efficiency and demand savings. As a result of the settlement, new rates were implemented on July 1, 2018, reflecting the impacts of the order, and the tax reserve balance estimated for January 2018 through June 2018 of $18.9 million was returned to Oklahoma customers during the July billing cycle. As reserved amounts were estimated through June 2018, a true-up mechanism exists for the difference between the estimate and actuals to be calculated after the determination of year-end financial results. Demand Program Rider - Energy Efficiency Lost Net Revenues During the May 2017 implementation of new rates from the March 2017 OCC rate order, OG&E reserved $5.6 million , pending resolution of a dispute with the OCC's Public Utility Division staff regarding recovery of certain lost revenues associated with energy efficiency programs incurred prior to the March 2017 OCC rate order. These lost revenues are recovered through the Demand Program Rider as disclosed in Note 1. This dispute was resolved through the June 19, 2018 Oklahoma rate review settlement discussed above; as a result, the reserve was reversed at June 30, 2018, and an adjustment was recorded to the Demand Program Rider regulatory asset balance. Fuel Adjustment Clause Review for Calendar Year 2016 On August 3, 2017, the OCC's Public Utility Division staff filed an application to review OG&E's fuel adjustment clause for calendar year 2016, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On February 7, 2018, an intervenor filed a recommendation to disallow the Oklahoma jurisdictional portion of $3.3 million related to wind sales in the SPP. On April 4, 2018, a Joint Stipulation and Settlement Agreement was filed with the OCC. As part of the agreement, the stipulating parties settled all claims regarding the issue of wind energy settlement costs for the period September 2016 through May 2017, and OG&E agreed to refund $2.4 million to customers related to wind sales in the SPP. On April 25, 2018, the OCC approved the Joint Stipulation and Settlement Agreement, and in May 2018, OG&E refunded this settlement amount to customers. FERC - Request for Waiver On May 22, 2018, OG&E submitted a request for waiver of applicable formula rate provisions in OG&E's Open Access Transmission Tariff and the SPP's Open Access Transmission Tariff. OG&E requested a waiver, effective January 1, 2018, to revise its 2018 projected net revenue requirement to reflect the federal corporate income tax rate reduction from 35 percent to 21 percent as a result of the 2017 Tax Act. On June 29, 2018, the FERC granted OG&E's request for waiver, effective January 1, 2018, which will allow OG&E to lower its current year projected net revenue requirement and provide benefits to customers through lower rates more promptly than if OG&E were to wait until the current year true-up adjustment to recognize the reduced federal corporate income tax rate. Based on the order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice. As the SPP adjusts the rates billed to OG&E's customers, OG&E reverses the reserve as the previous months in 2018 are resettled based on the lower tax rate. APSC Order - 2017 Tax Act On January 12, 2018, as a result of the 2017 Tax Act, the APSC ordered OG&E to prepare and file an analysis of the ratemaking effects of the 2017 Tax Act on OG&E's revenue requirement and begin, effective January 1, 2018, to book regulatory liabilities to record the current and deferred impacts of the 2017 Tax Act. On July 26, 2018, the APSC ordered OG&E to file a separate rider that includes the reduction in tax expense due to the 2017 Tax Act and amortization of the applicable excess accumulated deferred income taxes as a reduction in revenue requirement. On August 27, 2018, OG&E filed the request for a new Tax Adjustment Rider as well as filed updates to all riders with tax implications, which were then approved by the APSC on September 24, 2018. All rider changes were implemented on October 1, 2018. In October 2018, OG&E refunded the excess income taxes collected from January 1, 2018 through September 30, 2018 and also began refunding the amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act, plus carrying charges, from January 2018 through September 2018, which was approximately $7.7 million . As reserved amounts were estimated through September 2018, a true-up mechanism exists for the difference between the estimate and actuals to be calculated after the determination of year-end financial results. Integrated Resource Plans In September 2018, OG&E submitted its final 2018 IRP to the OCC and the APSC. The 2018 IRP identified a need for capacity, and OG&E issued a request for proposals to identify options to fill that capacity need. See "Pre-Approval for Acquisition of Existing Power Plants" under "Pending Regulatory Matters" for further discussion regarding the outcome of the request for proposal process. Demand Program Portfolio Filing Pursuant to OCC rules, OG&E is required to propose, implement and administer a portfolio of demand programs once every three years. On July 1, 2018, OG&E filed its proposed Demand Program Three Year Portfolio for the 2019 through 2021 program cycle, and on December 27, 2018, the OCC approved OG&E's 2019 through 2021 demand portfolio programs. Pending Regulatory Matters Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates. Environmental Compliance Plan On August 6, 2014, OG&E filed an application under Oklahoma Statute Title 17, Section 286 (B) with the OCC for approval of its plan to comply with the EPA's MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP, which includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas, as well as a recovery mechanism for the associated costs. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan and approval for a recovery mechanism for the associated costs. On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider. On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP under Oklahoma Statute Title 17, Section 286 (B), and on December 23, 2015, the OCC rejected OG&E's motion. On February 12, 2016, OG&E filed an application under Oklahoma Statute Title 17, Section 151, et seq. requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed, and OG&E seeks recovery in a general rate review. On April 28, 2016, the OCC approved the Dry Scrubber project. Two parties appealed the OCC's decision to the Oklahoma Supreme Court. On April 24, 2018, the Oklahoma Supreme Court ruled that the OCC did not have the authority to grant pre-approval of OG&E's Dry Scrubber project outside the authority of Oklahoma Statute Title 17, Section 286 (B). OG&E anticipates the total cost of Dry Scrubbers will be $520.0 million , including allowance for funds used during construction and capitalized ad valorem taxes. The Dry Scrubber system on Sooner Unit 1 completed certain emission testing in October 2018 and was placed into service. The Dry Scrubber system on Sooner Unit 2 completed certain emission testing in January 2019 and was placed into service. As of December 31, 2018 , OG&E has invested $504.3 million in the Dry Scrubbers. On December 31, 2018, OG&E filed a rate review with the OCC seeking recovery for the Dry Scrubber project, as further discussed below. FERC - Section 206 Filing In January 2018, the Oklahoma Municipal Power Authority filed a complaint at the FERC stating that the base return on common equity used by OG&E in calculating formula transmission rates under the SPP Open Access Transmission Tariff is unjust and unreasonable and should be reduced from 10.60 percent to 7.85 percent , effective upon the date of the complaint. The Company has reserved an amount within this range. The Company estimates that if the FERC ultimately orders a reduction, each 25 basis point reduction in the requested return on equity would reduce the Company's SPP Open Access Transmission Tariff transmission revenues by approximately $1.5 million annually. The Company contested the reduction of its base return on equity. While the Company is unable to predict what final action the FERC will take in response to the Oklahoma Municipal Power Authority's complaint or the timing of such action, if the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could have a material adverse effect on the Company's financial position, results of operations and cash flows. In addition to the request to reduce the return on equity, the Oklahoma Municipal Power Authority's complaint also requests that modifications be made to OG&E's transmission formula rates to reflect the impacts of the 2017 Tax Act, including the 2017 Tax Act's impact on accumulated deferred income tax balances. Based on an order received from the FERC, OG&E reserved the excess income taxes collected in current rates from January 2018 through June 2018, as the new tax rate was reflected in billings beginning with the July 2018 invoice, as discussed under "FERC - Request for Waiver" above. Further, OG&E is also reserving any amortization of excess accumulated deferred income taxes associated with the 2017 Tax Act. Fuel Adjustment Clause Review for Calendar Year 2017 On July 9, 2018, the OCC staff filed an application to review OG&E's fuel adjustment clause for the calendar year 2017, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. A hearing on the merits was held in December 2018, and on February 1, 2019, the Administrative Law Judge recommended that OG&E's processes, costs, investments and decisions regarding fuel procurement for the 2017 calendar year be found prudent. This recommendation is subject to OCC approval. Arkansas Formula Rate Plan Filing Per OG&E's settlement in its last general rate review in Arkansas, OG&E filed an evaluation report under its Formula Rate Plan on October 1, 2018, requesting a $6.4 million revenue increase. On January 30, 2019, OG&E and settling parties reached a settlement agreement for a $3.3 million revenue increase. The settlement agreement is subject to APSC approval. A final order is expected from the APSC in March 2019, and new rates will become effective on April 1, 2019. Oklahoma Rate Review Filing - December 2018 On December 31, 2018, OG&E filed a general rate review with the OCC, requesting a rate increase of $77.6 million per year to recover its investment in the Dry Scrubbers project and in the conversion of Muskogee Units 4 and 5 to natural gas to comply with the Regional Haze Rule. The filing also seeks to align OG&E's return on equity more closely to the industry average and to align OG&E's depreciation rates to more realistically reflect its assets' lifespans. Pre-Approval for Acquisition of Existing Power Plants On December 28, 2018, OG&E filed an application for pre-approval from the OCC to acquire a 360 MW coal- and natural gas-fired plant from AES and a 146 MW natural gas-fired combined-cycle plant from Oklahoma Cogeneration LLC in 2019 for $53.5 million . The purchase of these assets is intended to replace capacity currently provided by power purchase contracts set to expire in 2019 and to help OG&E satisfy its customers' energy needs and load obligations to the SPP. In addition, the filing seeks approval of a rider mechanism to collect costs associated with the purchase of these generating facilities.

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2018
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 2018 $ 492.7 $ 567.0 $ 698.8 $ 511.8 $ 2,270.3 2017 $ 456.0 $ 586.4 $ 716.8 $ 501.9 $ 2,261.1 Operating income 2018 $ 66.6 $ 137.7 $ 227.3 $ 58.0 $ 489.6 2017 $ 49.8 $ 147.3 $ 249.1 $ 85.7 $ 531.9 Net income 2018 $ 55.0 $ 110.7 $ 205.1 $ 54.7 $ 425.5 2017 $ 36.0 $ 104.8 $ 183.4 $ 294.8 $ 619.0 Basic earnings per average common share (A) 2018 $ 0.28 $ 0.55 $ 1.03 $ 0.27 $ 2.13 2017 $ 0.18 $ 0.52 $ 0.92 $ 1.48 $ 3.10 Diluted earnings per average common share (A) 2018 $ 0.27 $ 0.55 $ 1.02 $ 0.27 $ 2.12 2017 $ 0.18 $ 0.52 $ 0.92 $ 1.48 $ 3.10 (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, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
SEC Schedule, 12-09, 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, 2016 Reserve for Uncollectible Accounts $ 1.4 $ 2.5 $ 2.4 $ 1.5 Balance at December 31, 2017 Reserve for Uncollectible Accounts $ 1.5 $ 2.6 $ 2.6 $ 1.5 Balance at December 31, 2018 Reserve for Uncollectible Accounts $ 1.5 $ 1.6 $ 1.4 $ 1.7 (A) Uncollectible accounts receivable written off, net of recoveries.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation, Policy [Policy Text Block]	Organization The Company is a holding company with investments in energy and energy services providers offering physical delivery and related services for both electricity and natural gas primarily in the south central U.S. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and it lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas . Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma, and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through wholly owned subsidiaries and ultimately OGE Holdings. Enable was formed in 2013 , and its general partner is equally controlled by the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company accounts for its interest in Enable using the equity method of accounting. Enable is primarily engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex Basins. Enable also owns a crude oil gathering business in the Anadarko and Williston Basins. Enable has intrastate natural gas transportation and storage assets that are located in Oklahoma as well as interstate assets that extend from western Oklahoma and the Texas Panhandle to Louisiana, from Louisiana to Illinois and from Louisiana to Alabama.
Public Utilities, Policy [Policy Text Block]	Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets or liabilities, which could have significant financial effects.
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, which 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 $1.7 million and $1.5 million at December 31, 2018 and 2017 , 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 $57.6 million and $84.3 million at December 31, 2018 and 2017 , 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 2.7 percent and 2.5 percent of the average depreciable utility plant for 2018 and 2017 , respectively, is calculated using the 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 2019 , the provision for depreciation is projected to be 2.7 percent of the average depreciable utility plant. Amortization of intangible assets is calculated using the straight-line method. Of the remaining amortizable intangible plant balance at December 31, 2018 , 98.7 percent will be amortized over 10.4 years with the remaining 1.3 percent of the intangible plant balance at December 31, 2018 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 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 at December 31, 2018 as presented in Note 13. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and are classified as operating activities in the 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 Obligation [Policy Text Block]	Asset Retirement Obligations OG&E has asset retirement obligations primarily associated with the removal of company-owned wind turbines on leased land, as well as the removal of asbestos from certain power generating stations. The Company has recorded asset retirement obligations that are being accreted over their respective lives ranging from two 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, 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 is calculated according to the FERC requirements for the imputed cost of equity and borrowed funds. Allowance for funds used during construction rates, compounded semi-annually, were 7.6 percent , 8.2 percent and 8.2 percent for the years ended December 31, 2018 , 2017 and 2016 , 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. The performance obligation to deliver electricity is generally created and satisfied simultaneously, and the provisions of the regulatory-approved tariff determine the charges OG&E may bill the customer, payment due date and other pertinent rights and obligations of both parties. OG&E reads its customers' meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers' electricity consumption that has not been billed at the end of each month. OG&E accrues an estimate of the revenues for electric sales delivered since the latest billings. Unbilled revenue is presented in Accrued Unbilled Revenues on the Consolidated Balance Sheets and in Revenues from Contracts with Customers 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. Integrated Market and Transmission OG&E currently owns and operates transmission and generation facilities as part of a vertically integrated utility. OG&E is a member of the SPP regional transmission organization and has transferred operational authority, but not ownership, of OG&E's transmission facilities to the SPP. The SPP has implemented FERC-approved regional day ahead and real-time markets for energy and operating services, as well as associated transmission congestion rights. Collectively the three markets operate together under the global name, SPP Integrated Marketplace. OG&E represents owned and contracted generation assets and customer load in the SPP Integrated Marketplace for the sole benefit of its customers. OG&E has not participated in the SPP Integrated Marketplace for any speculative trading activities. OG&E records the SPP Integrated Marketplace transactions as sales or purchases per FERC Order 668, which requires that purchases and sales be recorded on a net basis for each settlement period of the SPP Integrated Marketplace. Purchases and sales are based on the fixed transaction price determined by the market at the time of the purchase or sale and the MWh quantity purchased or sold. These results are reported as Revenues from Contracts with Customers or Cost of Sales in the Consolidated Financial Statements. OG&E revenues, expenses, assets and liabilities may be adversely affected by changes in the organization, operating and regulation by the FERC or the SPP. OG&E's transmission revenues are generated by the use of OG&E's transmission network by the SPP, which operates the network, on behalf of other transmission owners. OG&E recognizes revenue on the sale of transmission service to its customers over time as the service is provided in the amount OG&E has a right to invoice. Transmission service to the SPP is billed monthly based on a fixed transaction price determined by OG&E's FERC-approved formula transmission rates along with other SPP-specific charges and the megawatt quantity reserved. Other Revenues Revenues from Alternative Revenue Programs Other Revenues on the Consolidated Statements of Income is comprised of certain rider revenue that includes alternative revenue measures as defined in ASC 980, "Regulated Operations," which details two types of alternative revenue programs. The first type adjusts billings for the effects of weather abnormalities or broad external factors or to compensate OG&E for demand-side management initiatives (i.e., no-growth plans and similar conservation efforts). The second type provides for additional billings (i.e., incentive awards) for the achievement of certain objectives, such as reducing costs, reaching specified milestones or demonstratively improving customer service. Once the specific events permitting billing of the additional revenues under either program type have been completed, OG&E recognizes the additional revenues if (i) the program is established by an order from OG&E's regulatory commission that allows for automatic adjustment of future rates; (ii) the amount of additional revenues for the period is objectively determinable and is probable of recovery; and (iii) the additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.
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.
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]	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 $23.4 million and $17.1 million in accrued environmental liabilities at December 31, 2018 and 2017 , respectively, which are included in the Company's asset retirement obligations.
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 Company had no financial instruments measured at fair value on a recurring basis at December 31, 2018 and 2017 . The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt 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. 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 are accrued on a quarterly basis pending achievement of payout criteria and are 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. 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 primarily 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 will only be paid on restricted stock awards that vest; therefore, 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 Company estimates expected forfeitures in accounting for performance unit compensation expense. 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 Sheets. 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.
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 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 stocks, U.S. Treasury notes and bonds, mutual funds and cash collateral. 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 mortgage- and asset-backed securities, corporate fixed income and other securities, foreign government bonds, U.S. municipal bonds, U.S. 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 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. The group retiree medical insurance contract invests in a pool of common stocks, bonds and money market accounts, of which a significant portion is comprised of mortgage-backed securities. 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. 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. The Company made a $15.0 million and $20.0 million contribution to its Pension Plan in 2018 and 2017 , respectively. The Company has not determined whether it will need to make any contributions to the Pension Plan in 2019 . Any contribution to the Pension Plan during 2019 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.
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 $1.9 million and $2.5 million at December 31, 2018 and 2017 , respectively.
Plan Investments, Policies and Strategies, Policy [Policy Text Block]	Pension 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 International ACWI ex-U.S. The fixed income managers are expected to use discretion over the asset mix of the trust assets in their 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 Service, S&P's Global Ratings 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-U.S. Index is the benchmark for comparative performance purposes. The Morgan Stanley Capital International All Country World ex-U.S. Index is a market value weighted index designed to measure the combined equity market performance of developed and emerging markets countries, excluding the U.S. 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, and 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 reached 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 their 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 requirements, 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 $13.2 million , $13.2 million and $11.9 million in 2018 , 2017 and 2016 , 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 2018 , 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 Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Regulatory Assets and Liabilities [Table Text Block]	The following table is a summary of OG&E's regulatory assets and liabilities: December 31 (In millions) 2018 2017 REGULATORY ASSETS Current: Production tax credit rider under recovery (A) $ 6.9 $ — Oklahoma demand program rider under recovery (A) 6.4 31.6 Fuel clause under recoveries 2.0 — SPP cost tracker under recovery (A) — 7.7 Other (A) 3.2 1.5 Total current regulatory assets $ 18.5 $ 40.8 Non-current: Benefit obligations regulatory asset $ 188.2 $ 177.2 Deferred storm expenses 36.5 42.2 Smart Grid 25.6 32.8 Unamortized loss on reacquired debt 11.4 12.3 Arkansas deferred pension expenses 6.8 5.1 Sooner Dry Scrubbers 4.5 — Other 12.8 13.4 Total non-current regulatory assets $ 285.8 $ 283.0 REGULATORY LIABILITIES Current: SPP cost tracker over recovery (B) $ 16.8 $ — Reserve for tax refund (B) 15.4 — Transmission cost recovery rider over recovery (B) 2.7 0.2 Fuel clause over recoveries 0.3 1.7 Other (B) 1.4 2.0 Total current regulatory liabilities $ 36.6 $ 3.9 Non-current: Income taxes refundable to customers, net $ 937.1 $ 955.5 Accrued removal obligations, net 308.1 288.4 Pension tracker 18.7 32.3 Other 6.8 7.2 Total non-current regulatory liabilities $ 1,270.7 $ 1,283.4 (A) Included in Other Current Assets on the Consolidated Balance Sheets. (B) Included in Other Current Liabilities on the Consolidated Balance Sheets.
Components of Benefit Obligation Regulatory Asset [Table Text Block]	The following table is a summary of the components of the benefit obligations regulatory asset: December 31 (In millions) 2018 2017 Pension Plan and Restoration of Retirement Income Plan: Net loss $ 185.3 $ 172.4 Postretirement Benefit Plans: Net loss 25.6 33.6 Prior service cost (22.7 ) (28.8 ) Total $ 188.2 $ 177.2
Schedule of Net Periodic Benefit Cost Not yet Recognized [Table Text Block]	The following amounts in the benefit obligations regulatory asset at December 31, 2018 are expected to be recognized as components of net periodic benefit cost in 2019 : (In millions) Pension Plan and Restoration of Retirement Income Plan: Net loss $ 13.8 Postretirement Benefit Plans: Net loss 2.7 Prior service cost (6.1 ) Total $ 10.4
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, 2018 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 227.2 $ 78.2 $ 149.0 Redbud Plant (A)(B) 51 % $ 493.9 $ 145.3 $ 348.6 (A) Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million . December 31, 2017 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment McClain Plant (A) 77 % $ 226.8 $ 71.4 $ 155.4 Redbud Plant (A)(B) 51 % $ 496.6 $ 136.0 $ 360.6 (A) Construction work in progress was $0.4 million and $7.8 million for the McClain and Redbud Plants, respectively. (B) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 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: December 31, 2018 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy: Property, plant and equipment $ 6.1 $ — $ 6.1 OGE Energy property, plant and equipment 6.1 — 6.1 OG&E: Distribution assets 4,229.4 1,324.5 2,904.9 Electric generation assets (A) 4,657.2 1,572.8 3,084.4 Transmission assets (B) 2,846.7 534.2 2,312.5 Intangible plant 187.6 135.1 52.5 Other property and equipment 444.2 160.8 283.4 OG&E property, plant and equipment 12,365.1 3,727.4 8,637.7 Total property, plant and equipment $ 12,371.2 $ 3,727.4 $ 8,643.8 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million . December 31, 2017 (In millions) Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment OGE Energy: Property, plant and equipment $ 6.1 $ — $ 6.1 OGE Energy property, plant and equipment 6.1 — 6.1 OG&E: Distribution assets 4,057.1 1,259.1 2,798.0 Electric generation assets (A) 4,475.0 1,493.5 2,981.5 Transmission assets (B) 2,767.7 506.5 2,261.2 Intangible plant 181.8 135.8 46.0 Other property and equipment 421.0 173.9 247.1 OG&E property, plant and equipment 11,902.6 3,568.8 8,333.8 Total property, plant and equipment $ 11,908.7 $ 3,568.8 $ 8,339.9 (A) This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million . (B) This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million .
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) 2018 2017 2016 OGE Energy $ — $ 0.2 $ 1.4 OG&E 9.6 8.8 8.0 Total $ 9.6 $ 9.0 $ 9.4
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, 2018 and 2017 . (In millions) 2018 2017 Balance at January 1 $ 75.1 $ 69.6 Accretion expense 3.4 3.1 Revisions in estimated cash flows (A) 6.8 2.4 Liabilities settled (1.4 ) — Balance at December 31 $ 83.9 $ 75.1 (A) Assumptions changed related to the estimated timing and estimated cost of ash pond removal at one of OG&E's generating facilities.
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 the Company during 2017 and 2018 . All amounts below are presented net of tax. Pension Plan and Restoration of Retirement Income Plan Postretirement Benefit Plans (In millions) Net Income Prior Service Cost (Credit) Net Income (Loss) Prior Service Cost (Credit) Total Balance at December 31, 2016 $ (32.1 ) $ 0.1 $ 2.7 $ — $ (29.3 ) Other comprehensive income (loss) before reclassifications 0.4 — (0.6 ) 6.3 6.1 Amounts reclassified from accumulated other comprehensive income (loss) 2.5 (0.1 ) — (0.6 ) 1.8 Cumulative effect of change in accounting principle (5.7 ) — (0.1 ) 1.3 (4.5 ) Settlement cost 2.2 — 0.5 — 2.7 Net current period other comprehensive income (0.6 ) (0.1 ) (0.2 ) 7.0 6.1 Balance at December 31, 2017 (32.7 ) — 2.5 7.0 (23.2 ) Other comprehensive income (loss) before reclassifications (14.1 ) — 2.1 — (12.0 ) Amounts reclassified from accumulated other comprehensive income (loss) 3.3 — — (1.7 ) 1.6 Settlement cost 4.7 — — — 4.7 Net current period other comprehensive income (loss) (6.1 ) — 2.1 (1.7 ) (5.7 ) Balance at December 31, 2018 $ (38.8 ) $ — $ 4.6 $ 5.3 $ (28.9 )
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, 2018 and 2017 . Details about Accumulated Other Comprehensive Income (Loss) Components Amount Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Consolidated Statements of Income Year Ended December 31, (In millions) 2018 2017 Amortization of Pension Plan and Restoration of Retirement Income Plan items: Actuarial losses (A) $ (4.4 ) $ (3.9 ) Other Net Periodic Benefit Expense Prior service cost — 0.1 Other Net Periodic Benefit Expense Settlement cost (A) (6.3 ) (3.6 ) Other Net Periodic Benefit Expense (10.7 ) (7.4 ) Income Before Taxes (2.7 ) (2.8 ) Income Tax Expense (Benefit) $ (8.0 ) $ (4.6 ) Net Income Amortization of postretirement benefit plans items: Prior service cost $ 2.3 $ 0.9 Other Net Periodic Benefit Expense Settlement cost (A) — (0.7 ) Other Net Periodic Benefit Expense 2.3 0.2 Income Before Taxes 0.6 0.1 Income Tax Expense (Benefit) $ 1.7 $ 0.1 Net Income Total reclassifications for the period $ (6.3 ) $ (4.5 ) Net Income (A) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost (see Note 12 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 (gain) at December 31, 2018 that are expected to be recognized into earnings in 2019 are as follows: (In millions) Pension Plan and Restoration of Retirement Income Plan: Net gain $ (4.9 ) Postretirement Benefit Plans: Net loss 0.3 Prior service cost 2.3 Total, net of tax $ (2.3 )

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table disaggregates the Company's revenues from contracts with customers by customer classification. The Company's operating revenues disaggregated by customer classification can be found in "OG&E (Electric Utility) Results of Operations" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." (In millions) Year Ended Residential $ 877.8 Commercial 578.0 Industrial 191.1 Oilfield 150.2 Public authorities and street light 197.4 System sales revenues 1,994.5 Provision for rate refund (6.0 ) Integrated market 48.7 Transmission 147.4 Other 27.1 Revenues from contracts with customers $ 2,211.7

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliate and Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
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, 2018 and 2017 and for the years ended December 31, 2018 , 2017 and 2016 . Balance Sheet December 31, (In millions) 2018 2017 Current assets $ 449 $ 416 Non-current assets $ 11,995 $ 11,177 Current liabilities $ 1,615 $ 1,279 Non-current liabilities $ 3,211 $ 2,660
Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]	Income Statement Year Ended December 31, (In millions) 2018 2017 2016 Total revenues $ 3,431 $ 2,803 $ 2,272 Cost of natural gas and NGLs $ 1,819 $ 1,381 $ 1,017 Operating income $ 648 $ 528 $ 385 Net income $ 485 $ 400 $ 290
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, 2018 , 2017 and 2016 , respectively. Year Ended December 31, (In millions) 2018 2017 2016 Enable net income $ 485.3 $ 400.3 $ 289.5 Distributions senior to limited partners — — (9.1 ) Differences due to timing of OGE Energy and Enable accounting close — — (12.2 ) Enable net income used to calculate OGE Energy's equity in earnings $ 485.3 $ 400.3 $ 268.2 OGE Energy's percent ownership at period end 25.6 % 25.7 % 25.7 % OGE Energy's portion of Enable net income $ 124.4 $ 102.7 $ 70.7 Impairments recognized by Enable associated with OGE Energy's basis difference — — 2.6 OGE Energy's share of Enable net income 124.4 102.7 73.3 Amortization of basis difference 11.2 11.3 11.6 Elimination of Enable fair value step up 17.2 17.2 16.9 Equity in earnings of unconsolidated affiliates $ 152.8 $ 131.2 $ 101.8
Reconciliation of Basis Difference [Table Text Block]	The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $680.3 million as of December 31, 2018 . The following table reconciles the basis difference in Enable from December 31, 2017 to December 31, 2018 . (In millions) Basis difference at December 31, 2017 $ 714.2 Change in Enable basis difference (5.5 ) Amortization of basis difference (11.2 ) Elimination of Enable fair value step up (17.2 ) Basis difference at December 31, 2018 $ 680.3
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, 2018 , 2017 and 2016 . Year Ended December 31, (In millions) 2018 2017 2016 Operating revenues: Electricity to power electric compression assets $ 16.3 $ 14.0 $ 11.5 Cost of sales: Natural gas transportation services $ 37.9 $ 35.0 $ 35.0 Natural gas (sales) purchases $ (3.2 ) $ (2.1 ) $ 11.2

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 . 2018 2017 December 31 (In millions) Carrying Amount Fair Carrying Amount Fair Long-term Debt (including Long-term Debt due within one year): Senior Notes $ 3,001.9 $ 3,178.2 $ 2,854.3 $ 3,242.8 OG&E Industrial Authority Bonds $ 135.4 $ 135.4 $ 135.4 $ 135.4 Tinker Debt $ 9.6 $ 8.7 $ 9.7 $ 9.8

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 related to the Company's performance units and restricted stock . Year Ended December 31 (In millions) 2018 2017 2016 Performance units: Total shareholder return $ 8.2 $ 7.6 $ 4.5 Earnings per share 5.1 1.4 — Total performance units 13.3 9.0 4.5 Restricted stock 0.1 0.1 0.1 Total compensation expense $ 13.4 $ 9.1 $ 4.6 Income tax benefit $ 3.4 $ 3.5 $ 1.8
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. 2018 2017 2016 Number of units granted 261,916 260,570 284,211 Fair value of units granted $ 36.86 $ 41.77 $ 20.97 Expected dividend yield 3.6 % 3.8 % 3.5 % Expected price volatility 19.0 % 19.9 % 19.8 % Risk-free interest rate 2.38 % 1.44 % 0.88 % Expected life of units (in years) 2.86 2.80 2.84
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. 2018 2017 2016 Number of units granted 87,308 86,857 94,735 Fair value of units granted $ 31.03 $ 34.83 $ 26.64
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. 2018 2017 2016 Shares of restricted stock granted 826 3,145 1,881 Fair value of restricted stock granted $ 36.28 $ 34.96 $ 29.27
Share-based Compensation, Activity [Table Text Block]	A summary of the activity for the Company's performance units and restricted stock at December 31, 2018 and changes in 2018 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 12/31/17 724,551 241,518 4,242 Granted 261,916 (A) 87,308 (A) 826 Converted (201,431 ) (B) $ — (67,148 ) (B) $ 1.2 N/A Vested N/A N/A (2,357 ) $ 0.1 Forfeited (29,556 ) (9,853 ) — Units/shares outstanding at 12/31/18 755,480 $ 53.2 251,825 $ 14.1 2,711 $ 0.1 Units/shares fully vested at 12/31/18 274,078 $ 19.8 91,356 $ 7.2 (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, 2017 which were settled in February 2018.
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, 2018 and changes in 2018 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 12/31/17 523,120 $ 30.96 174,370 $ 30.58 4,242 $ 33.58 Granted 261,916 (A) $ 36.86 87,308 (A) $ 31.03 826 $ 36.28 Vested (274,078 ) $ 21.69 (91,356 ) $ 26.93 (2,357 ) $ 32.84 Forfeited (29,556 ) $ 35.55 (9,853 ) $ 31.94 — $ — Units/shares non-vested at 12/31/18 481,402 $ 39.17 160,469 $ 32.82 2,711 $ 35.00 Units/shares expected to vest 464,027 (B) 154,678 (B) 2,711 (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) The intrinsic value of the performance units based on total shareholder return and earnings per share is $32.0 million and $6.8 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) 2018 2017 2016 Performance units: Total shareholder return $ 5.9 $ 6.3 $ 6.4 Earnings per share $ 4.9 $ 1.2 $ — Restricted stock $ 0.1 $ 0.1 $ 0.1
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, 2018 Unrecognized Compensation Cost (In millions) Weighted Average to be Recognized (In years) Performance units: Total shareholder return $ 9.0 1.65 Earnings per share 2.5 1.66 Total performance units 11.5 Restricted stock 0.1 1.94 Total unrecognized compensation cost $ 11.6

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2018
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. Cash paid for interest, net of interest capitalized, and cash paid for income taxes, net of income tax refunds are also disclosed in the table. Year Ended December 31 (In millions) 2018 2017 2016 NON-CASH INVESTING AND FINANCING ACTIVITIES Power plant long-term service agreement $ (9.2 ) $ (2.6 ) $ 39.5 SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the period for: Interest (net of interest capitalized) (A) $ 153.8 $ 139.6 $ 141.9 Income taxes (net of income tax refunds) $ 2.8 $ (16.0 ) $ (5.9 ) (A) Net of interest capitalized of $11.7 million , $18.0 million and $7.5 million in 2018 , 2017 and 2016 , respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The items comprising income tax expense (benefit) are as follows: Year Ended December 31 (In millions) 2018 2017 2016 Provision (benefit) for current income taxes: Federal $ (1.9 ) $ 4.9 $ — State (4.4 ) (4.2 ) (5.7 ) Total provision (benefit) for current income taxes (6.3 ) 0.7 (5.7 ) Provision (benefit) for deferred income taxes, net: Federal 74.7 (75.9 ) 126.0 State 3.7 26.0 28.0 Total provision (benefit) for deferred income taxes, net 78.4 (49.9 ) 154.0 Deferred federal investment tax credits, net 0.1 (0.1 ) (0.2 ) Total income tax expense (benefit) $ 72.2 $ (49.3 ) $ 148.1
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 2018 2017 2016 Statutory federal tax rate 21.0 % 35.0 % 35.0 % Federal deferred tax revaluation 0.4 (41.2 ) — Other 0.4 (0.1 ) 0.1 State income taxes, net of federal income tax benefit 0.4 2.0 1.9 Executive compensation limitation 0.2 — — Federal renewable energy credit (A) (5.1 ) (4.8 ) (6.8 ) Amortization of net unfunded deferred taxes (2.1 ) 0.7 0.7 Remeasurement of state deferred tax liabilities (0.4 ) 0.4 0.9 401(k) dividends (0.3 ) (0.5 ) (0.6 ) Federal investment tax credits, net — (0.1 ) (0.8 ) Uncertain tax positions — — 0.1 Effective income tax rate 14.5 % (8.6 )% 30.5 % (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, 2018 and 2017 were as follows: December 31 (In millions) 2018 2017 Deferred income tax liabilities, net: Accelerated depreciation and other property related differences $ 1,605.3 $ 1,449.6 Investment in Enable 469.9 441.7 Regulatory assets 17.4 18.9 Company Pension Plan 7.6 11.5 Bond redemption-unamortized costs 2.4 2.6 Derivative instruments 1.7 1.6 Other 1.1 (0.9 ) Income taxes recoverable from customers, net (239.6 ) (244.3 ) Federal tax credits (237.8 ) (218.5 ) State tax credits (156.0 ) (141.7 ) Regulatory liabilities (78.8 ) (16.8 ) Postretirement medical and life insurance benefits (23.6 ) (25.2 ) Asset retirement obligations (21.5 ) (19.2 ) Net operating losses (20.2 ) (21.1 ) Accrued liabilities (12.5 ) (7.4 ) Accrued vacation (2.3 ) (2.1 ) Deferred federal investment tax credits (1.8 ) (0.5 ) Uncollectible accounts (0.4 ) (0.4 ) Total deferred income tax liabilities, net $ 1,310.9 $ 1,227.8
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, 2018 , 2017 and 2016 . (In millions) 2018 2017 2016 Balance at January 1 $ 20.7 $ 20.7 $ 20.2 Tax positions related to current year: Additions — — 0.5 Balance at December 31 $ 20.7 $ 20.7 $ 20.7
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 State operating loss $ 451.8 $ 20.2 2030 Federal tax credits $ 237.8 $ 237.8 2032 State tax credits: Oklahoma investment tax credits $ 161.6 $ 127.7 N/A Oklahoma capital investment board credits $ 8.9 $ 8.9 N/A Oklahoma zero emission tax credits $ 24.1 $ 19.4 2020 N/A - not applicable

Common Equity (Tables)

Common Equity (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2018 2017 2016 Net income $ 425.5 $ 619.0 $ 338.2 Average common shares outstanding: Basic average common shares outstanding 199.7 199.7 199.7 Effect of dilutive securities: Contingently issuable shares (performance and restricted stock units) 0.8 0.3 0.2 Diluted average common shares outstanding 200.5 200.0 199.9 Basic earnings per average common share $ 2.13 $ 3.10 $ 1.69 Diluted earnings per average common share $ 2.12 $ 3.10 $ 1.69 Anti-dilutive shares excluded from earnings per share calculation — — —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows: SERIES DATE DUE AMOUNT (In millions) 1.01% - 2.00% Garfield Industrial Authority, January 1, 2025 $ 47.0 1.01% - 1.83% Muskogee Industrial Authority, January 1, 2025 32.4 1.03% - 1.86% Muskogee Industrial Authority, June 1, 2027 56.0 Total (redeemable during next 12 months) $ 135.4

Short-Term Debt and Credit Fa_2

Short-Term Debt and Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2018
Short-term Debt [Abstract]
Schedule of Line of Credit Facilities [Table Text Block]	The following table provides information regarding the Company's revolving credit agreements at December 31, 2018 . Aggregate Amount Weighted-Average Entity Commitment Outstanding (A) Interest Rate Expiration (In millions) OGE Energy (B) $ 450.0 $ — — % (D) March 8, 2023 (E) OG&E (C) 450.0 0.3 1.05 % (D) March 8, 2023 (E) Total $ 900.0 $ 0.3 1.05 % (A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2018 . (B) This bank facility is available to back up the Company's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. (D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit. (E) In March 2017, the Company and OG&E entered into unsecured five-year revolving credit agreements totaling $900.0 million ( $450.0 million for the Company and $450.0 million for OG&E). Each of the facilities contained an option, which could be exercised up to two times, to extend the term of the respective facility for an additional year. Effective March 9, 2018, the Company and OG&E utilized one of those extensions to extend the maturity of their respective credit facility from March 8, 2022 to March 8, 2023.

Retirement Plans and Postreti_2

Retirement Plans and Postretirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 and 2017 . 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, 2018 was $561.9 million and $7.8 million , respectively. The accumulated postretirement benefit obligation for the Pension Plan and the Restoration of Retirement Income Plan at December 31, 2017 was $ 626.9 million and $ 7.5 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 included in the following table. Pension Plan Restoration of Retirement Postretirement December 31 (In millions) 2018 2017 2018 2017 2018 2017 Change in benefit obligation Beginning obligations $ 687.5 $ 672.2 $ 8.1 $ 7.0 $ 149.4 $ 215.9 Service cost 14.9 15.5 0.4 0.3 0.3 0.6 Interest cost 23.8 26.2 0.3 0.3 5.4 7.2 Plan settlements (73.7 ) (50.2 ) (2.0 ) — — (28.1 ) Plan amendments — — — — — (39.6 ) Participants' contributions — — — — 3.8 3.5 Actuarial losses (gains) (22.0 ) 38.6 2.8 0.7 (9.6 ) 5.6 Benefits paid (14.6 ) (14.8 ) — (0.2 ) (13.5 ) (15.7 ) Ending obligations $ 615.9 $ 687.5 $ 9.6 $ 8.1 $ 135.8 $ 149.4 Change in plans' assets Beginning fair value $ 635.3 $ 595.9 $ — $ — $ 50.2 $ 53.1 Actual return on plans' assets (39.2 ) 84.4 — — (0.6 ) 2.8 Employer contributions 15.0 20.0 2.0 0.2 5.4 34.6 Plan settlements (73.7 ) (50.2 ) (2.0 ) — — (28.1 ) Participants' contributions — — — — 3.8 3.5 Benefits paid (14.6 ) (14.8 ) — (0.2 ) (13.5 ) (15.7 ) Ending fair value $ 522.8 $ 635.3 $ — $ — $ 45.3 $ 50.2 Funded status at end of year $ (93.1 ) $ (52.2 ) $ (9.6 ) $ (8.1 ) $ (90.5 ) $ (99.2 )
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following table presents the net periodic benefit cost components, before consideration of capitalized amounts, of the Company's Pension Plan, Restoration of Retirement Income Plan and postretirement benefit plans that are included in the Consolidated Financial Statements. Service cost is presented within Other Operation and Maintenance, and interest cost, expected return on plan assets, amortization of net loss, amortization of unrecognized prior service cost and settlement cost are presented within Other Net Periodic Benefit Expense in the Company's Consolidated Statements of Income. OG&E recovers specific amounts of pension and postretirement medical costs in rates approved in its Oklahoma rate reviews. In accordance with approved orders, OG&E defers the difference between actual pension and postretirement medical expenses and the amount approved in its last Oklahoma rate review as a regulatory asset or regulatory liability. These amounts have been recorded in the Pension tracker in the regulatory assets and liabilities table in Note 1 and within Other Net Periodic Benefit Expense in the Company's Consolidated Statements of Income. Pension Plan Restoration of Retirement Postretirement Benefit Plans Year Ended December 31 (In millions) 2018 2017 2016 2018 2017 2016 2018 2017 2016 Service cost $ 14.9 $ 15.5 $ 15.8 $ 0.4 $ 0.3 $ 0.3 $ 0.3 $ 0.6 $ 0.8 Interest cost 23.8 26.2 25.5 0.3 0.3 0.4 5.4 7.2 9.5 Expected return on plan assets (44.1 ) (42.6 ) (41.5 ) — — — (2.0 ) (2.2 ) (2.3 ) Amortization of net loss 16.2 17.4 16.5 0.7 0.4 0.7 3.8 2.0 2.6 Amortization of unrecognized prior service cost (A) — (0.1 ) (0.1 ) 0.1 0.1 0.1 (8.4 ) (3.5 ) (8.8 ) Settlement cost 25.1 15.3 — 1.0 — 8.6 — 0.6 — Total net periodic benefit cost 35.9 31.7 16.2 2.5 1.1 10.1 (0.9 ) 4.7 1.8 Less: Amount paid by unconsolidated affiliates 2.5 4.3 5.1 0.1 — 0.3 (0.5 ) 0.3 0.2 Net periodic benefit cost (B) $ 33.4 $ 27.4 $ 11.1 $ 2.4 $ 1.1 $ 9.8 $ (0.4 ) $ 4.4 $ 1.6 (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 $35.4 million , $32.9 million and $22.5 million of net periodic benefit cost recognized in 2018 , 2017 and 2016 , respectively, OG&E recognized the following: • a change in pension expense in 2018 , 2017 and 2016 of $(14.1) million , $(2.3) million and $9.9 million , respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1); • an increase in postretirement medical expense in 2018 , 2017 and 2016 of $4.4 million , $6.2 million and $7.9 million , respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and • a deferral of pension expense in 2018, 2017 and 2016 of $2.1 million , $1.1 million and $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $26.1 million , $15.3 million and $8.6 million , respectively, which are included in the Arkansas deferred pension expense regulatory asset (see Note 1).
Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]	(In millions) 2018 2017 2016 Capitalized portion of net periodic pension benefit cost $ 3.8 $ 4.4 $ 4.0 Capitalized portion of net periodic postretirement benefit cost $ 0.2 $ 1.2 $ 0.8
Schedule of Assumptions Used [Table Text Block]	Rate Assumptions Pension Plan and Postretirement Year Ended December 31 2018 2017 2016 2018 2017 2016 Assumptions to determine benefit obligations: Discount rate 4.20 % 3.60 % 4.00 % 4.30 % 3.70 % 4.20 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A 4.20 % Assumptions to determine net periodic benefit cost: Discount rate 3.73 % 4.00 % 4.00 % 3.70 % 4.20 % 4.25 % Expected return on plan assets 7.50 % 7.50 % 7.50 % 4.00 % 4.00 % 4.00 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A 4.20 % 4.20 % 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) 2018 2017 2016 Effect on aggregate of the service and interest cost components $ — $ — $ — Effect on accumulated postretirement benefit obligations $ 0.1 $ 0.1 $ 0.2 ONE-PERCENTAGE POINT DECREASE Year Ended December 31 (In millions) 2018 2017 2016 Effect on aggregate of the service and interest cost components $ — $ — $ — Effect on accumulated postretirement benefit obligations $ 0.3 $ 0.3 $ 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 Pension Plan's investments that are measured at fair value on a recurring basis at December 31, 2018 and 2017 . There were no Level 3 investments held by the Pension Plan at December 31, 2018 and 2017 . (In millions) December 31, 2018 Level 1 Level 2 Net Asset Value (A) Common stocks $ 169.3 $ 169.3 $ — $ — U.S. Treasury notes and bonds (B) 137.9 137.9 — — Mortgage- and asset-backed securities 65.9 — 65.9 — Corporate fixed income and other securities 143.2 — 143.2 — Commingled fund (C) 19.7 — — 19.7 Foreign government bonds 4.4 — 4.4 — U.S. municipal bonds 0.6 — 0.6 — Money market fund 0.3 — — 0.3 Mutual fund 8.0 8.0 — — Futures: U.S. Treasury futures (receivable) 27.0 — 27.0 — U.S. Treasury futures (payable) (20.4 ) — (20.4 ) — Cash collateral 0.7 0.7 — — Forward contracts: Receivable (foreign currency) 0.1 — 0.1 — Total Pension Plan investments $ 556.7 $ 315.9 $ 220.8 $ 20.0 Receivable from broker for securities sold — Interest and dividends receivable 3.0 Payable to broker for securities purchased (36.9 ) Total Pension Plan assets $ 522.8 (A) GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy. (B) This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher. (C) This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets. (In millions) December 31, 2017 Level 1 Level 2 Net Asset Value (A) Common stocks $ 225.9 $ 225.9 $ — $ — U.S. Treasury notes and bonds (B) 169.7 169.7 — — Mortgage- and asset-backed securities 43.4 — 43.4 — Corporate fixed income and other securities 153.8 — 153.8 — Commingled fund (C) 29.9 — — 29.9 Foreign government bonds 4.0 — 4.0 — U.S. municipal bonds 1.2 — 1.2 — Money market fund 4.3 — — 4.3 Mutual fund 7.8 7.8 — — Futures: U.S. Treasury futures (receivable) 13.4 — 13.4 — U.S. Treasury futures (payable) (11.4 ) — (11.4 ) — Cash collateral 0.3 0.3 — — Forward contracts: Receivable (foreign currency) 0.1 — 0.1 — Total Pension Plan investments $ 642.4 $ 403.7 $ 204.5 $ 34.2 Receivable from broker for securities sold — Interest and dividends receivable 3.2 Payable to broker for securities purchased (10.3 ) Total Pension Plan assets $ 635.3 (A) GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy. (B) This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher. (C) This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets. The following tables summarize the postretirement benefit plans' investments that are measured at fair value on a recurring basis at December 31, 2018 and 2017 . There were no Level 2 investments held by the postretirement benefit plans at December 31, 2018 and 2017 . (In millions) December 31, 2018 Level 1 Level 3 Group retiree medical insurance contract $ 36.0 $ — $ 36.0 Mutual funds 8.9 8.9 — Cash 0.9 0.9 — Total plan investments $ 45.8 $ 9.8 $ 36.0 (In millions) December 31, 2017 Level 1 Level 3 Group retiree medical insurance contract $ 40.2 $ — $ 40.2 Mutual funds 9.5 9.5 — Cash 0.5 0.5 — Total plan investments $ 50.2 $ 10.0 $ 40.2
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) 2018 Group retiree medical insurance contract: Beginning balance $ 40.2 Interest income 0.7 Dividend income 0.5 Claims paid (4.6 ) Net unrealized losses related to instruments held at the reporting date (0.5 ) Realized losses (0.2 ) Investment fees (0.1 ) Ending balance $ 36.0
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 2019 $ 11.6 2020 $ 11.6 2021 $ 11.6 2022 $ 11.6 2023 $ 10.2 After 2023 $ 46.7 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 2019 $ 64.3 2020 $ 60.2 2021 $ 60.6 2022 $ 59.7 2023 $ 59.7 After 2023 $ 267.6

Report of Business Segments (Ta

Report of Business Segments (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following tables summarize the results of the Company's business segments for the years ended December 31, 2018 , 2017 and 2016 . 2018 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 2,270.3 $ — $ — $ — $ 2,270.3 Cost of sales 892.5 — — — 892.5 Other operation and maintenance 473.8 1.4 (0.6 ) — 474.6 Depreciation and amortization 321.6 — — — 321.6 Taxes other than income 88.2 0.6 3.2 — 92.0 Operating income (loss) 494.2 (2.0 ) (2.6 ) — 489.6 Equity in earnings of unconsolidated affiliates — 152.8 — — 152.8 Other income (expense) 25.6 (4.9 ) (3.4 ) (6.0 ) 11.3 Interest expense 151.8 — 10.2 (6.0 ) 156.0 Income tax expense (benefit) 40.0 37.1 (4.9 ) — 72.2 Net income (loss) $ 328.0 $ 108.8 $ (11.3 ) $ — $ 425.5 Investment in unconsolidated affiliates $ — $ 1,166.6 $ 10.9 $ — $ 1,177.5 Total assets $ 9,704.5 $ 1,169.8 $ 184.8 $ (310.5 ) $ 10,748.6 Capital expenditures $ 573.6 $ — $ — $ — $ 573.6 2017 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 2,261.1 $ — $ — $ — $ 2,261.1 Cost of sales 897.6 — — — 897.6 Other operation and maintenance 469.8 (0.8 ) (10.3 ) — 458.7 Depreciation and amortization 280.9 — 2.6 — 283.5 Taxes other than income 84.8 1.0 3.6 — 89.4 Operating income (loss) 528.0 (0.2 ) 4.1 — 531.9 Equity in earnings of unconsolidated affiliates — 131.2 — — 131.2 Other income (expense) 57.7 (1.0 ) (5.4 ) (0.9 ) 50.4 Interest expense 138.4 — 6.3 (0.9 ) 143.8 Income tax expense (benefit) (A) 141.8 (195.2 ) 4.1 — (49.3 ) Net income (loss) $ 305.5 $ 325.2 $ (11.7 ) $ — $ 619.0 Investment in unconsolidated affiliates $ — $ 1,151.9 $ 8.5 $ — $ 1,160.4 Total assets $ 9,255.6 $ 1,155.3 $ 109.1 $ (107.3 ) $ 10,412.7 Capital expenditures $ 824.1 $ — $ — $ — $ 824.1 (A) The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act. See Note 8 for further discussion of the effects of the 2017 Tax Act. 2016 Electric Utility Natural Gas Midstream Operations Other Eliminations Total (In millions) Operating revenues $ 2,259.2 $ — $ — $ — $ 2,259.2 Cost of sales 880.1 — — — 880.1 Other operation and maintenance 451.2 (0.1 ) (13.0 ) — 438.1 Depreciation and amortization 316.4 — 6.2 — 322.6 Taxes other than income 84.0 — 3.6 — 87.6 Operating income 527.5 0.1 3.2 — 530.8 Equity in earnings of unconsolidated affiliates — 101.8 — — 101.8 Other income (expense) 9.1 (7.7 ) (5.4 ) (0.2 ) (4.2 ) 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

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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) 2019 2020 2021 2022 2023 After 2023 Total Operating lease obligations: Railcars $ 18.6 $ — $ — $ — $ — $ — $ 18.6 Wind farm land leases 2.5 2.9 2.9 2.9 2.9 37.6 51.7 Office space lease 1.0 1.0 0.6 — — — 2.6 Total operating lease obligations $ 22.1 $ 3.9 $ 3.5 $ 2.9 $ 2.9 $ 37.6 $ 72.9
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) 2019 2020 2021 2022 2023 Total Other purchase obligations and commitments: Cogeneration capacity and fixed operation and maintenance payments (A) $ 10.9 $ — $ — $ — $ — $ 10.9 Expected cogeneration energy payments (A) 2.4 — — — — 2.4 Minimum purchase commitments 75.8 44.6 44.6 44.6 44.6 254.2 Expected wind purchase commitments 56.3 56.9 57.1 57.5 58.0 285.8 Long-term service agreement commitments 46.8 2.4 2.4 2.4 14.4 68.4 Environmental compliance plan expenditures 5.8 0.2 — — — 6.0 Total other purchase obligations and commitments $ 198.0 $ 104.1 $ 104.1 $ 104.5 $ 117.0 $ 627.7 (A) Cogeneration capacity, fixed operation and maintenance and energy payments will end in 2019, as a result of contract expiration. As described below, OG&E intends to acquire the AES and Oklahoma Cogeneration LLC power plants, pending regulatory approval.
Schedule of Wind Power Purchases [Table Text Block]	OG&E owns the 120 MW Centennial, 101 MW OU Spirit and 228 MW Crossroads wind farms. OG&E's current wind power portfolio also includes purchased power contracts as listed in the table below. Company Location Original Term of Contract Expiration of Contract MWs CPV Keenan Woodward County, OK 20 years 2030 152.0 Edison Mission Energy Dewey County, OK 20 years 2031 130.0 NextEra Energy Blackwell, OK 20 years 2032 60.0 The following table summarizes OG&E's wind power purchases for the years ended December 31, 2018 , 2017 and 2016 . Year Ended December 31 (In millions) 2018 2017 2016 CPV Keenan $ 27.0 $ 29.0 $ 29.2 Edison Mission Energy 21.7 22.1 21.1 NextEra Energy 6.8 7.4 7.3 FPL Energy (A) 2.1 2.6 3.4 Total wind power purchased $ 57.6 $ 61.1 $ 61.0 (A) OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 $ 492.7 $ 567.0 $ 698.8 $ 511.8 $ 2,270.3 2017 $ 456.0 $ 586.4 $ 716.8 $ 501.9 $ 2,261.1 Operating income 2018 $ 66.6 $ 137.7 $ 227.3 $ 58.0 $ 489.6 2017 $ 49.8 $ 147.3 $ 249.1 $ 85.7 $ 531.9 Net income 2018 $ 55.0 $ 110.7 $ 205.1 $ 54.7 $ 425.5 2017 $ 36.0 $ 104.8 $ 183.4 $ 294.8 $ 619.0 Basic earnings per average common share (A) 2018 $ 0.28 $ 0.55 $ 1.03 $ 0.27 $ 2.13 2017 $ 0.18 $ 0.52 $ 0.92 $ 1.48 $ 3.10 Diluted earnings per average common share (A) 2018 $ 0.27 $ 0.55 $ 1.02 $ 0.27 $ 2.12 2017 $ 0.18 $ 0.52 $ 0.92 $ 1.48 $ 3.10 (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, 2018
SEC Schedule, 12-09, 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, 2016 Reserve for Uncollectible Accounts $ 1.4 $ 2.5 $ 2.4 $ 1.5 Balance at December 31, 2017 Reserve for Uncollectible Accounts $ 1.5 $ 2.6 $ 2.6 $ 1.5 Balance at December 31, 2018 Reserve for Uncollectible Accounts $ 1.5 $ 1.6 $ 1.4 $ 1.7 (A) Uncollectible accounts receivable written off, net of recoveries.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Regulated Operations (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries		$ 2	$ 0
Fuel clause over recoveries		0.3	1.7
Regulatory Assets, Current		18.5	40.8
Regulatory Assets, Noncurrent		285.8	283
Regulatory Liability, Current		36.6	3.9
Regulatory Liability, Noncurrent		1,270.7	1,283.4
SPP Cost Tracker Rider Under Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	16.8	0
Reserve for Tax Refund [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	15.4	0
Transmission Cost Recovery Rider [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	2.7	0.2
Income taxes recoverable from customers, net [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		937.1	955.5
Accrued removal obligations [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		308.1	288.4
Pension tracker [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Noncurrent		18.7	32.3
Other Regulatory Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	[1]	1.4	2
Regulatory Liability, Noncurrent		6.8	7.2
Production Tax Credit Rider [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	6.9	0
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	6.4	31.6
SPP Cost Tracker Rider Under Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	0	7.7
Benefit obligations regulatory asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		188.2	177.2
Deferred storm expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		36.5	42.2
Smart Grid [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		25.6	32.8
Unamortized loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		11.4	12.3
Deferred Pension Expenses [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		6.8	5.1
Dry Scrubber Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Noncurrent		4.5	0
Other Regulatory Assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	[2]	3.2	1.5
Regulatory Assets, Noncurrent		$ 12.8	$ 13.4
[1]	Included in Other Current Liabilities on the Consolidated Balance Sheets.
[2]	Included in Other Current Assets on the Consolidated Balance Sheets.

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Accounting Records (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets, Current	$ 18.5	$ 40.8
Regulatory Assets, Noncurrent	285.8	283
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	(2.3)
Deferred Storm and Property Reserve Deficiency, Current	2.7
Regulatory Liability, Current	36.6	3.9
Pension Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Components of Benefit Obligation Regulatory Asset	185.3	172.4
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	13.8
Other Postretirement Benefit Plans, Defined Benefit [Member] | Defined Benefit Plans Income Loss [Member]
Components of Benefit Obligation Regulatory Asset	25.6	33.6
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	2.7
Other Postretirement Benefit Plans, Defined Benefit [Member] | Prior Service Cost [Member]
Components of Benefit Obligation Regulatory Asset	(22.7)	$ (28.8)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	(6.1)
Regulatory Asset [Member]
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year	$ 10.4

Summary of Significant Accoun_6

Summary of Significant Accounting Policies Allowance for Uncollectible Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Allowance for Doubtful Accounts Receivable	$ 1.7	$ 1.5

Summary of Significant Accoun_7

Summary of Significant Accounting Policies Fuel Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2014
Other	$ 29.5	$ 54.6
Public Utilities, Inventory, Fuel [Member]
Public Utilities, Inventory	$ 57.6	$ 84.3
Other Assets			$ 11

Summary of Significant Accoun_8

Summary of Significant Accounting Policies Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 12,371.2		$ 11,908.7
Accumulated Depreciation	3,727.4		3,568.8
Net property, plant and equipment	8,643.8		8,339.9
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	56.3		50.8
Capitalized Computer Software, Amortization	$ 9.6		$ 9		$ 9.4
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	$ 227.2	[1]	$ 226.8	[2]
Accumulated Depreciation	78.2	[1]	71.4	[2]
Net property, plant and equipment	149	[1]	155.4	[2]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 0.2		$ 0.4
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	$ 493.9	[1],[3]	$ 496.6	[2],[4]
Accumulated Depreciation	145.3	[1],[3]	136	[2],[4]
Net property, plant and equipment	348.6	[1],[3]	360.6	[2],[4]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0.9		7.8
Amount of Acquisition Adjustments	148.3		148.3
OGE Energy [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	6.1		6.1
Accumulated Depreciation	0		0
Net property, plant and equipment	6.1		6.1
Capitalized Computer Software, Amortization	0		0.2		1.4
OGE Energy [Member] | Total Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	6.1		6.1
Accumulated Depreciation	0		0
Net property, plant and equipment	6.1		6.1
OG&E [Member]
Property, Plant and Equipment [Line Items]
Capitalized Computer Software, Gross	44.3		37.5
Capitalized Computer Software, Amortization	9.6		8.8		$ 8
OG&E [Member] | Total Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	12,365.1		11,902.6
Accumulated Depreciation	3,727.4		3,568.8
Net property, plant and equipment	8,637.7		8,333.8
OG&E [Member] | Electric Transmission and Distribution [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	4,229.4		4,057.1
Accumulated Depreciation	1,324.5		1,259.1
Net property, plant and equipment	2,904.9		2,798
OG&E [Member] | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	4,657.2	[5]	4,475	[6]
Accumulated Depreciation	1,572.8	[5]	1,493.5	[6]
Net property, plant and equipment	3,084.4	[5]	2,981.5	[6]
Amount of Acquisition Adjustments	148.3		148.3
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	56.3		50.8
OG&E [Member] | Electric Transmission [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,846.7	[7]	2,767.7	[8]
Accumulated Depreciation	534.2	[7]	506.5	[8]
Net property, plant and equipment	2,312.5	[7]	2,261.2	[8]
Amount of Acquisition Adjustments	3.3		3.3
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments, Related Accumulated Depreciation	0.7		0.6
OG&E [Member] | Finite-Lived Intangible Assets, Major Class Name [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	187.6		181.8
Accumulated Depreciation	135.1		135.8
Net property, plant and equipment	52.5		46
OG&E [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	444.2		421
Accumulated Depreciation	160.8		173.9
Net property, plant and equipment	$ 283.4		$ 247.1
[1]	Construction work in progress was $0.2 million and $0.9 million for the McClain and Redbud Plants, respectively.
[2]	Construction work in progress was $0.4 million and $7.8 million for the McClain and Redbud Plants, respectively.
[3]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.
[4]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million.
[5]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $56.3 million.
[6]	This amount includes a plant acquisition adjustment of $148.3 million and accumulated amortization of $50.8 million.
[7]	This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.7 million.
[8]	This amount includes a plant acquisition adjustment of $3.3 million and accumulated amortization of $0.6 million.

Summary of Significant Accoun_9

Summary of Significant Accounting Policies Depreciation and Amortization (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Provision for Depreciation Rate	2.70%	2.50%
Projected provision for depreciation in next fiscal year	2.70%
Percent Of Intangible Plant Balance Amortizable	98.70%
Percent of Intangible Plant Balance Amortizable Thereafter	1.30%
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 Accou_10

Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Current Fiscal Year End Date	--12-31
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 75.1	$ 69.6
Accretion expense	3.4	3.1
Revisions in estimated cash flows	6.8	2.4
Liabilities settled	(1.4)	0
Balance at December 31	$ 83.9	$ 75.1

Summary of Significant Accou_11

Summary of Significant Accounting Policies Enviromental Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accrued Environmental Loss Contingencies, Noncurrent	$ 23.4	$ 17.1

Summary of Significant Accou_12

Summary of Significant Accounting Policies Allowance for Funds Used During Construction (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Allowance for Funds Used During Construction, Rate	7.60%	8.20%	8.20%

Summary of Significant Accou_13

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive (income) loss		$ (28.9)	$ (23.2)	$ (29.3)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		(12)	6.1
Amounts reclassified from accumulated other comprehensive income (loss)		(3.3)	(2.5)	(2.8)
Amounts reclassified from accumulated other comprehensive income (loss)		1.6	1.8
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification			(4.5)
Net current period other comprehensive income (loss)		(5.7)	6.1
Amounts Reclassified from Accumulated OCI, Net of Tax and Noncontrolling Interest		6.3	4.5
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		(2.3)
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)		(8)	(4.6)
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, before Tax	[1]	(4.4)	(3.9)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax		0	0.1
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	[1]	(6.3)	(3.6)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		(10.7)	(7.4)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		(2.7)	(2.8)
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		1.7	0.1
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, before Tax		2.3	0.9
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), before Tax	[1]	0	(0.7)
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, before Tax		2.3	0.2
Other Comprehensive (Income) Loss, Defined Benefit Plan, Reclassification Adjustment from AOCI, Tax		0.6	0.1
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)		(38.8)	(32.7)	(32.1)
Other comprehensive income before reclassifications		(14.1)	0.4
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			0
Amounts reclassified from accumulated other comprehensive income (loss)		3.3	2.5
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification			(5.7)
Net current period other comprehensive income (loss)		(6.1)	(0.6)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		(4.9)
Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		4.6	2.5	2.7
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		2.1	(0.6)
Amounts reclassified from accumulated other comprehensive income (loss)		0	0
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification			(0.1)
Net current period other comprehensive income (loss)		2.1	(0.2)
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		0.3
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	0	0.1
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		0
Amounts reclassified from accumulated other comprehensive income (loss)		0	(0.1)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification			0
Net current period other comprehensive income (loss)		0	(0.1)
Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated other comprehensive income (loss)		5.3	7	$ 0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		0	6.3
Amounts reclassified from accumulated other comprehensive income (loss)		(1.7)	(0.6)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification			1.3
Net current period other comprehensive income (loss)		(1.7)	7
Components of Net Periodic Benefit Costs to be Recognized in Next Fiscal Year		2.3
Settlement Cost [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		4.7	2.7
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)		4.7	2.2
Settlement Cost [Member] | Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss)		0	0.5
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 Benefits Plan [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 loss components are included in the computation of net periodic benefit cost (see Note 12 for additional information).

Accounting Pronouncements New A

Accounting Pronouncements New Accounting Pronouncement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets		$ 38
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ (4.5)

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue from Contract with Customer, Excluding Assessed Tax	$ 2,211.7	$ 0	$ 0
Provision for Rate Refund [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	(6)
Integrated Market [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	48.7
Transmission [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	147.4
Other Contracts with Customers [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	27.1
Residential [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	877.8
Commercial [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	578
Industrial [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	191.1
Oilfield [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	150.2
Public Authority [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	197.4
Total Retail Customer [Member]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,994.5

Investment in Unconsolidated _3

Investment in Unconsolidated Affiliate and Related Party Transactions (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	May 01, 2013
Schedule of Equity Method Investments [Line Items]
Limited Partner Units Owned	111
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.60%	25.70%	25.70%
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.31800
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 680.3	$ 714.2
Equity in earnings of unconsolidated affiliates	152.8	131.2	$ 101.8
Enable Midstream Partners [Member]
Schedule of Equity Method Investments [Line Items]
Distributions received	$ 141.2	141.2	141.2
Enogex LLC [Member]
Schedule of Equity Method Investments [Line Items]
Increase in fair value of net assets				$ 2,200
OGE Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.60%
OGE Energy [Member]
Schedule of Equity Method Investments [Line Items]
Goodwill, Impairment Loss	$ 0	0	(2.6)
Percentage Share of Management Rights	50.00%
CenterPoint [Member]
Schedule of Equity Method Investments [Line Items]
Percentage Share of Management Rights	50.00%
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	$ 152.8	$ 131.2	$ 101.8

Investment in Unconsolidated _4

Investment in Unconsolidated Affiliate and Related Party Transactions Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Expected Settlement Charge	$ 20.4
Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	16.3	$ 14	$ 11.5
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	0.6	2.3	4.7
Natural Gas Transportation [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	37.9	35	35
Natural Gas Purchases [Member] | Og and E [Member] | Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	(3.2)	(2.1)	11.2
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	27.5	29.5	$ 28.7
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 1.7	$ 2

Investment in Unconsolidated _5

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Summarized Financial Information of Equity Method Investment [Line Items]
Current assets	$ 449	$ 416
Non-current assets	11,995	11,177
Current liabilities	1,615	1,279
Non-current liabilities	$ 3,211	$ 2,660

Investment in Unconsolidated _6

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Total revenues	$ 3,431	$ 2,803	$ 2,272
Cost of natural gas and NGL	1,819	1,381	1,017
Operating income	648	528	385
Net income	$ 485.3	$ 400.3	$ 289.5

Investment in Unconsolidated _7

Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Net income	$ 485.3	$ 400.3	$ 289.5
Timing Differences Related to Equity Method Investee Net Income	0	0	(12.2)
Net Income Used to Calculate Equity in Earnings	$ 485.3	$ 400.3	$ 268.2
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.60%	25.70%	25.70%
Proportionate Unconsolidated Affiliate Net Income	$ 124.4	$ 102.7	$ 70.7
OGE Energy's share of Enable net income	124.4	102.7	73.3
Amortization of basis difference	11.2	11.3	11.6
Elimination of Enable fair value step up	17.2	17.2	16.9
Equity in earnings of unconsolidated affiliates	152.8	131.2	101.8
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	152.8	131.2	101.8
Preferred Partner [Member]
Schedule of Equity Method Investments [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 0	0	(9.1)
OGE Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	25.60%
OGE Energy [Member]
Schedule of Equity Method Investments [Line Items]
Goodwill, Impairment Loss	$ 0	$ 0	$ 2.6
Amortization of basis difference	$ 11.2

Investment in Unconsolidated _8

Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Basis Difference (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Basis Difference [Line Items]
Equity in Earnings Amortization of Basis Difference	$ 11.2	$ 11.3	$ 11.6
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	680.3	714.2
Equity in Earnings Change in Basis Difference	(5.5)
Elimination of Enable fair value step up	17.2	$ 17.2	$ 16.9
OGE Energy [Member]
Reconciliation of Basis Difference [Line Items]
Equity in Earnings Amortization of Basis Difference	$ 11.2

Fair Value Measurements Carryin

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	$ 3,146.9	$ 2,999.4
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,001.9	2,854.3
Long-Term Debt, Fair Value	3,178.2	3,242.8
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	9.6	9.7
Long-Term Debt, Fair Value	8.7	9.8
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

Stock Based Compensation (Detai

Stock Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Authorized		7,400,000
Tax Benefit from Compensation Expense		$ 3.4		$ 3.5	$ 1.8
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		$ 11.6
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		87,308	[1]	86,857	94,735
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 31.03		$ 34.83	$ 26.64
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		251,825		241,518
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		87,308	[1]	86,857	94,735
Equity Instruments Other than Options, Converted in Period	[2]	(67,148)
Equity Instruments Other than Options, Forfeited in Period		(9,853)
Awards Other than Options, Fully Vested		91,356
Equity Instruments Other than Options, Converted, Aggregrate Intrinsic Value		$ 1.2
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		7.2
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		14.1
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 6.8
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		174,370
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		87,308	[1]	86,857	94,735
Equity Instruments Other than Options, Vested in Period		(91,356)
Equity Instruments Other than Options, Forfeited in Period		(9,853)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		160,469		174,370
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 32.82		$ 30.58
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		31.03		$ 34.83	$ 26.64
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		26.93
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 31.94
Awards Other than Options, Vested and Expected to Vest, Outstanding	[3]	154,678
Fair Value of Vested Performance Units and Restricted Stock		$ 4.9		$ 1.2	$ 0
Total Compensation Cost Not yet Recognized		$ 2.5
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 7 months 28 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		261,916	[1]	260,570	284,211
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 36.86		$ 41.77	$ 20.97
Expected Dividend Rate		3.60%		3.80%	3.50%
Expected Volatility Rate		19.00%		19.90%	19.80%
Risk Free Interest Rate		2.38%		1.44%	0.88%
Expected Term		2 years 10 months 10 days		2 years 9 months 18 days	2 years 10 months 2 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		755,480		724,551
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		261,916	[1]	260,570	284,211
Equity Instruments Other than Options, Converted in Period	[2]	(201,431)
Equity Instruments Other than Options, Forfeited in Period		(29,556)
Awards Other than Options, Fully Vested		274,078
Equity Instruments Other than Options, Converted, Aggregrate Intrinsic Value		$ 0
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		19.8
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		53.2
Equity Instruments Other than Options, Fully Vested, Aggregrate Intrinsic Value		$ 32
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		523,120
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		261,916	[1]	260,570	284,211
Equity Instruments Other than Options, Vested in Period		(274,078)
Equity Instruments Other than Options, Forfeited in Period		(29,556)
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		481,402		523,120
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 39.17		$ 30.96
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		36.86		$ 41.77	$ 20.97
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		21.69
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 35.55
Awards Other than Options, Vested and Expected to Vest, Outstanding	[3]	464,027
Fair Value of Vested Performance Units and Restricted Stock		$ 5.9		$ 6.3	$ 6.4
Total Compensation Cost Not yet Recognized		$ 9
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 7 months 24 days
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 13.3		9	4.5
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		11.5
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 0.1		$ 0.1	$ 0.1
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		826		3,145	1,881
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 36.28		$ 34.96	$ 29.27
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		2,711		4,242
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		826		3,145	1,881
Equity Instruments Other than Options, Forfeited in Period		0
Equity Instruments Other than Options, Vested in Period, Aggregate Intrinsic Value		$ 0.1
Equity Instruments Other than Options, Outstanding, Aggregrate Intrinsic Value		$ 0.1
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		4,242
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted		826		3,145	1,881
Equity Instruments Other than Options, Vested in Period		(2,357)
Equity Instruments Other than Options, Forfeited in Period		0
Equity Instruments Other than Options, Nonvested, Number, Ending Balance		2,711		4,242
Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 35		$ 33.58
Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		36.28		$ 34.96	$ 29.27
Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		32.84
Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 0
Awards Other than Options, Vested and Expected to Vest, Outstanding		2,711
Fair Value of Vested Performance Units and Restricted Stock		$ 0.1		$ 0.1	$ 0.1
Total Compensation Cost Not yet Recognized		$ 0.1
Total Compensation Cost Not yet Recognized, Period for Recognition		1 year 11 months 9 days
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense, Net of Unconsolidated Affiliates		$ 13.4		9.1	4.6
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		5.1		1.4	0
Total Shareholder Return [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense		$ 8.2		$ 7.6	$ 4.5
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		26,211		2,298	2,100
[1]	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.
[2]	These amounts represent performance units that vested at December 31, 2017 which were settled in February 2018.
[3]	The intrinsic value of the performance units based on total shareholder return and earnings per share is $32.0 million

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
NON-CASH INVESTING AND FINANCING ACTIVITIES
Power plant long-term service agreement		$ (9.2)	$ (2.6)	$ 39.5
SUPPLEMENTAL CASH FLOW INFORMATION
Interest (net of interest capitalized)	[1]	153.8	139.6	141.9
Income taxes (net of income tax refunds)		2.8	(16)	(5.9)
Interest costs capitalized		$ 11.7	$ 18	$ 7.5
[1]	Net of interest capitalized of $11.7 million, $18.0 million and $7.5 million in 2018, 2017 and 2016, respectively.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Regulatory Liability, Noncurrent		$ 1,270.7	$ 1,283.4
Interim Rate Revenue Reserved		15.4
Increase in Tax Expense from Adjustment		2.1
Current Federal Tax Expense (Benefit)		(1.9)	4.9		$ 0
Current State and Local Tax Expense (Benefit)		(4.4)	(4.2)		(5.7)
Current Income Tax Expense (Benefit)		(6.3)	0.7		(5.7)
Deferred Federal Income Tax Expense (Benefit)		74.7	(75.9)		126
Deferred State and Local Income Tax Expense (Benefit)		3.7	26		28
Deferred Income Tax Expense (Benefit)		78.4	(49.9)		154
Investment Tax Credit		0.1	(0.1)		(0.2)
Income Tax Expense (Benefit)		$ 72.2	$ (49.3)	[1]	$ 148.1
Statutory federal tax rate		21.00%	35.00%		35.00%
Federal deferred tax revaluation		0.40%	(41.20%)		0.00%
Federal renewable energy credit (A)	[2]	(5.10%)	(4.80%)		(6.80%)
Remeasurement of state deferred tax liabilities		(0.40%)	0.40%		0.90%
401(k) dividends		(0.30%)	(0.50%)		(0.60%)
Federal investment tax credits, net		0.00%	(0.10%)		(0.80%)
State income taxes, net of federal income tax benefit		0.40%	2.00%		1.90%
Effective Income Tax Rate Reconciliation, Executive Compensation Limitation, Percent		0.20%	0.00%		0.00%
Uncertain tax positions		0.00%	0.00%		0.10%
Amortization of net unfunded deferred taxes		(2.10%)	0.70%		0.70%
Other		0.40%	(0.10%)		0.10%
Effective income tax rate		14.50%	(8.60%)		30.50%
Accrued liabilities		$ (12.5)	$ (7.4)
Accrued vacation		(2.3)	(2.1)
Uncollectible accounts		(0.4)	(0.4)
Accelerated depreciation and other property related differences		1,605.3	1,449.6
Investment in Enable		469.9	441.7
Regulatory assets		17.4	18.9
Income taxes recoverable from customers, net		(239.6)	(244.3)
Company Pension Plan		7.6	11.5
Bond redemption-unamortized costs		2.4	2.6
Derivative instruments		1.7	1.6
Federal tax credits		(237.8)	(218.5)
State tax credits		(156)	(141.7)
Postretirement medical and life insurance benefits		(23.6)	(25.2)
Net operating losses		(20.2)	(21.1)
Regulatory liabilities		(78.8)	(16.8)
Asset retirement obligations		(21.5)	(19.2)
Deferred federal investment tax credits		(1.8)	(0.5)
Other		1.1	(0.9)
Total deferred income tax liabilities, net		1,310.9	1,227.8
Unrecognized Tax Benefits		20.7	20.7		$ 20.7	$ 20.2
Current year additions		0	0		0.5
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued		0
Tax Credit Carryforward, Deferred Tax Asset		237.8	218.5
Increased Regulatory Liabilities due to Income Taxes		7.4
State operating loss [Member]
Operating Loss Carryforwards		451.8
Deferred Tax Assets, Operating Loss Carryforwards, State and Local		$ 20.2
Tax Credit Carryforward, Expiration Date		Dec. 31, 2030
Federal tax credits [Member]
Federal tax credits		$ (237.8)
Tax Credit Carryforward, Amount		237.8
Tax Credit Carryforward, Deferred Tax Asset		$ 237.8
Tax Credit Carryforward, Expiration Date		Dec. 31, 2032
Oklahoma investment tax credits [Member]
State tax credits		$ (127.7)
Tax Credit Carryforward, Amount		161.6
Oklahoma capital investment board credits [Member]
State tax credits		(8.9)
Tax Credit Carryforward, Amount		8.9
Oklahoma zero emission tax credits [Member]
State tax credits		(19.4)
Tax Credit Carryforward, Amount		$ 24.1
Tax Credit Carryforward, Expiration Date		Dec. 31, 2020
Og and E [Member]
Unrecognized Tax Benefits		$ 16.4	$ 16.4		$ 13.5
Income taxes refundable to customers, net [Member]
Regulatory Liability, Noncurrent		$ 1,022
[1]	The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act. See Note 8 for further discussion of the effects of the 2017 Tax Act.
[2]	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) - Automatic Dividend Reinvestment and Stock Purchase Plan [Member]	12 Months Ended
	Dec. 31, 2018shares
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, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount																	0		0		0
Net income attributable to OGE Energy	$ 54.7		$ 205.1		$ 110.7		$ 55		$ 294.8		$ 183.4		$ 104.8		$ 36		$ 425.5		$ 619		$ 338.2
Basic Average Common Shares Outstanding																	199.7		199.7		199.7
Contingently Issuable Shares (Performance and Restricted Stock Units)																	0.8		0.3		0.2
Diluted Average Common Shares Outstanding																	200.5		200		199.9
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.27	[1]	$ 1.03	[1]	$ 0.55	[1]	$ 0.28	[1]	$ 1.48	[1]	$ 0.92	[1]	$ 0.52	[1]	$ 0.18	[1]	$ 2.13	[1]	$ 3.10	[1]	$ 1.69
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.27	[1]	$ 1.02	[1]	$ 0.55	[1]	$ 0.27	[1]	$ 1.48	[1]	$ 0.92	[1]	$ 0.52	[1]	$ 0.18	[1]	$ 2.12	[1]	$ 3.10	[1]	$ 1.69
Retained Earnings [Member]
Net income attributable to OGE Energy																	$ 425.5		$ 619		$ 338.2
[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, 2018USD ($)shares
Preferred Stock, Shares Outstanding | shares	0
OGE Energy [Member]
Ratio of Consolidated Debt to Consolidated Capitalization	65.00%
Retained Earnings, Restricted	$ 580.5
Retained Earnings, Unrestricted	$ 2,300
Og and E [Member]
Ratio of Consolidated Debt to Consolidated Capitalization	65.00%
Retained Earnings, Restricted	$ 674.9
Retained Earnings, Unrestricted	$ 1,900

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt	$ 3,146.9	$ 2,999.4
Percent of Principal Amount Subject to Optional Tender	100.00%
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 250.1
Long-term Debt, Maturities, Repayments of Principal in Year Two	0.1
Long-term Debt, Maturities, Repayments of Principal in Year Three	0.1
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
Senior Notes [Member] | OG&E [Member] | Series due August 15, 2028 [Member]
Debt Instrument [Line Items]
Long term debt, gross	$ 400
Debt Instrument, Interest Rate, Stated Percentage	3.80%
Date Due	Aug. 15, 2028
Senior Notes [Member] | OG&E [Member] | Series due September 1, 2018 [Member]
Debt Instrument [Line Items]
Long term debt, gross	$ 0	$ 250
Debt Instrument, Interest Rate, Stated Percentage	6.35%	6.35%
Date Due	Sep. 1, 2018	Sep. 1, 2018
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	1.01%
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	1.01%
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	1.03%
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	2.00%
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	1.83%
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	1.86%

Short-Term Debt and Credit Fa_3

Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Short-term debt		$ 0	$ 168.4
Line of Credit Facility [Abstract]
Aggregate Commitment		900
Amount Outstanding	[1]	$ 0.3
Weighted Average Interest Rate		1.05%
OGE Energy [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[2]	$ 450
Line of Credit Facility [Abstract]
Amount Outstanding	[1],[2]	$ 0
Weighted Average Interest Rate	[2],[3]	0.00%
Maturity		Mar. 8, 2023
Ratio of Consolidated Debt to Consolidated Capitalization		65.00%
OG&E [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[4]	$ 450
Line of Credit Facility [Abstract]
Letters of Credit Outstanding, Amount	[1],[4]	$ 0.3
Weighted Average Interest Rate	[3],[4]	1.05%
Maturity		Mar. 8, 2023
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800
Ratio of Consolidated Debt to Consolidated Capitalization		65.00%
Uninsured Judgements [Member] | OGE Energy [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		$ 100
Uninsured Judgements [Member] | OG&E [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		$ 100
[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at December 31, 2018.
[2]	This bank facility is available to back up the Company's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.
[3]	Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
[4]	This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

Retirement Plans and Postreti_3

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
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, Change in Fair Value of Plan Assets [Roll Forward]
Employer contributions		$ 15		$ 20
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement		26.1		15.3	$ 8.6
Net periodic benefit cost		35.4		32.9	22.5
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		0.1		0.1	0.2
Effect of One Percentage Point Decrease on Service and Interest Cost Components		0		0	0
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation		0.3		0.3	0.7
Expected Future Benefit Payments, Next Twelve Months		64.3
Expected Future Benefit Payments, Year Two		60.2
Expected Future Benefit Payments, Year Three		60.6
Expected Future Benefit Payments, Year Four		59.7
Expected Future Benefit Payments, Year Five		59.7
Expected Future Benefit Payments, Five Fiscal Years Thereafter		267.6
Defined Contribution Plan, Cost		13.2		13.2	11.9
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0		0
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		(14.6)		(14.8)
Accumulated Benefit Obligation		561.9		626.9
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		687.5		672.2
Service cost		14.9		15.5	15.8
Interest cost		23.8		26.2	25.5
Plan settlements		(73.7)		(50.2)
Participants' contributions		0		0
Actuarial gains (losses)		(22)		38.6
Benefit Obligation, Ending		615.9		687.5	672.2
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		635.3		595.9
Actual return on plans' assets		(39.2)		84.4
Employer contributions		15		20
Plan settlements		(73.7)		(50.2)
Fair Value of Plan Assets, Ending		522.8		635.3	595.9
Funded Status of Plan		(93.1)		(52.2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		14.9		15.5	15.8
Interest cost		23.8		26.2	25.5
Expected return on plan assets		(44.1)		(42.6)	(41.5)
Defined Benefit Plan, Amortization of Gain (Loss)		(16.2)		(17.4)	(16.5)
Amortization of unrecognized prior service cost		0		(0.1)	(0.1)	[1]
Settlement		25.1		15.3	0
Net periodic benefit cost		35.9		31.7	16.2
Amount paid by unconsolidated affiliates		2.5		4.3	5.1
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]	33.4		27.4	11.1
Plan settlements		(73.7)		(50.2)
Capitalized Portion of Net Periodic Benefit Cost		$ 3.8		$ 4.4	$ 4
Assumptions Used Calculating Benefit Obligation, Discount Rate		4.20%		3.60%	4.00%
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		$ 635.3		$ 595.9
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		0		0
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(14.6)		(14.8)
Pension Plans, Defined Benefit [Member] | OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Pension Expense to Meet State Requirements		(14.1)		(2.3)	$ 9.9
Pension Plans, Defined Benefit [Member] | ARKANSAS
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement		(2.1)		(1.1)	(0.1)
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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 Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		225.9
Fair Value of Plan Assets, Ending		169.3		225.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		225.9
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		225.9
Fair Value of Plan Assets, Ending		169.3		225.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		225.9
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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 Investment	[3],[4]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[4]	169.7
Fair Value of Plan Assets, Ending	[4]	137.9		169.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[4]	169.7
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	[4]	169.7
Fair Value of Plan Assets, Ending	[4]	137.9		169.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[4]	169.7
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	[4]	0
Fair Value of Plan Assets, Ending	[4]	0		0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[4]	0
Pension Plans, Defined Benefit [Member] | Mortgage-backed securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		43.4
Fair Value of Plan Assets, Ending		65.9		43.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		43.4
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		43.4
Fair Value of Plan Assets, Ending		65.9		43.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		43.4
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 Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		153.8
Fair Value of Plan Assets, Ending		143.2		153.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		153.8
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		153.8
Fair Value of Plan Assets, Ending		143.2		153.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		153.8
Pension Plans, Defined Benefit [Member] | Commingled fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3],[5]			29.9
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[5]	29.9
Fair Value of Plan Assets, Ending	[5]	19.7	[3]	29.9
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[5]	29.9
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	[5]	0
Fair Value of Plan Assets, Ending	[5]	0		0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[5]	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	[5]	0
Fair Value of Plan Assets, Ending	[5]	0		0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning	[5]	0
Pension Plans, Defined Benefit [Member] | Foreign government bonds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		4
Fair Value of Plan Assets, Ending		4.4		4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		4
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		4
Fair Value of Plan Assets, Ending		4.4		4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		4
Pension Plans, Defined Benefit [Member] | Municipal bonds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		1.2
Fair Value of Plan Assets, Ending		0.6		1.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		1.2
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		1.2
Fair Value of Plan Assets, Ending		0.6		1.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		1.2
Pension Plans, Defined Benefit [Member] | Money market funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	0.3		4.3
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		4.3
Fair Value of Plan Assets, Ending		0.3		4.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		4.3
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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 Investment	[3]	0		0
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		7.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		7.8
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		7.8
Fair Value of Plan Assets, Ending		8		7.8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		7.8
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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 Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		13.4
Fair Value of Plan Assets, Ending		27		13.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		13.4
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		13.4
Fair Value of Plan Assets, Ending		27		13.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		13.4
Pension Plans, Defined Benefit [Member] | Treasury futures, payable [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	0		0
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		(11.4)
Fair Value of Plan Assets, Ending		(20.4)		(11.4)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		(11.4)
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		(11.4)
Fair Value of Plan Assets, Ending		(20.4)		(11.4)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		(11.4)
Pension Plans, Defined Benefit [Member] | Cash collateral [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	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		0.7		0.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		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, Beginning		0.3
Fair Value of Plan Assets, Ending		0.7		0.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		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, Beginning		0
Fair Value of Plan Assets, Ending		0		0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0
Pension Plans, Defined Benefit [Member] | Receivable (foreign currency) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	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 (Credit) [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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		0.1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0.1
Pension Plans, Defined Benefit [Member] | Total Plan investments [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative Investment	[3]	20		34.2
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		642.4
Fair Value of Plan Assets, Ending		556.7		642.4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		642.4
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		403.7
Fair Value of Plan Assets, Ending		315.9		403.7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		403.7
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		204.5
Fair Value of Plan Assets, Ending		220.8		204.5
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		204.5
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
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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		3.2
Fair Value of Plan Assets, Ending		3		3.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		3.2
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		(10.3)
Fair Value of Plan Assets, Ending		(36.9)		(10.3)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		(10.3)
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		635.3
Fair Value of Plan Assets, Ending		522.8		635.3
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		635.3
Restoration of Retirement Income Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		0		(0.2)
Accumulated Benefit Obligation		7.8		7.5
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		8.1		7
Service cost		0.4		0.3	0.3
Interest cost		0.3		0.3	0.4
Plan settlements		(2)		0
Participants' contributions		0		0
Actuarial gains (losses)		2.8		0.7
Benefit Obligation, Ending		9.6		8.1	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		2		0.2
Plan settlements		(2)		0
Fair Value of Plan Assets, Ending		0		0	0
Funded Status of Plan		(9.6)		(8.1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.4		0.3	0.3
Interest cost		0.3		0.3	0.4
Expected return on plan assets		0		0	0
Defined Benefit Plan, Amortization of Gain (Loss)		(0.7)		(0.4)	(0.7)
Amortization of unrecognized prior service cost		0.1		0.1	0.1	[1]
Settlement		1		0	8.6
Net periodic benefit cost		2.5		1.1	10.1
Amount paid by unconsolidated affiliates		0.1		0	0.3
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]	2.4		1.1	9.8
Plan settlements		(2)		0
Fair Value of Plan Assets, Beginning		0		0
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		0		0
Defined Benefit Plan, Benefit Obligation, Benefits Paid		0		(0.2)
Other Postretirement Benefits Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Benefits Paid		(13.5)		(15.7)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		149.4		215.9
Service cost		0.3		0.6	0.8
Interest cost		5.4		7.2	9.5
Plan settlements		0		(28.1)
Participants' contributions		3.8		3.5
Actuarial gains (losses)		(9.6)		5.6
Benefit Obligation, Ending		135.8		149.4	215.9
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		50.2		53.1
Actual return on plans' assets		(0.6)		2.8
Employer contributions		5.4		34.6
Plan settlements		0		(28.1)
Fair Value of Plan Assets, Ending		45.3		50.2	53.1
Funded Status of Plan		(90.5)		(99.2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.3		0.6	0.8
Interest cost		5.4		7.2	9.5
Expected return on plan assets		(2)		(2.2)	(2.3)
Defined Benefit Plan, Amortization of Gain (Loss)		(3.8)		(2)	(2.6)
Amortization of unrecognized prior service cost		(8.4)		(3.5)	(8.8)	[1]
Settlement		0		0.6	0
Net periodic benefit cost		(0.9)		4.7	1.8
Amount paid by unconsolidated affiliates		(0.5)		0.3	0.2
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]	(0.4)		4.4	1.6
Plan settlements		0		(28.1)
Capitalized Portion of Net Periodic Benefit Cost		$ 0.2		$ 1.2	$ 0.8
Assumptions Used Calculating Benefit Obligation, Discount Rate		4.30%		3.70%	4.20%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		4.00%		4.00%	4.00%
Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase				4.20%	4.20%
Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.25%
Fair Value of Plan Assets, Beginning		$ 50.2		$ 53.1
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		3.8		3.5
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(13.5)		(15.7)
Other Postretirement Benefits Plan [Member] | OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Additional Postretirement Medical Expense to Meet State Requirements		4.4		6.2	$ 7.9
Other Postretirement Benefits Plan [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		10
Fair Value of Plan Assets, Ending		9.8		10
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		10
Other Postretirement Benefits Plan [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 (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0
Other Postretirement Benefits Plan [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		40.2
Fair Value of Plan Assets, Ending		36		40.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		40.2
Other Postretirement Benefits Plan [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		50.2
Fair Value of Plan Assets, Ending		45.8		50.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		50.2
Restoration of Retirement Income Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		0		0
Postretirement Benefit Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment		$ 0		(39.6)
Less Than 90% [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [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 (Credit) [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 (Credit) [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 (Credit) [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 (Credit) [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 (Credit) [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 (Credit) [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 (Credit) [Abstract]
Target Plan Asset Allocations		40.00%
Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		15.00%
Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		25.00%
International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		20.00%
Minimum [Member] | Domestic All-Cap/Large Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		35.00%
Minimum [Member] | Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		5.00%
Minimum [Member] | Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		5.00%
Minimum [Member] | International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		10.00%
Maximum [Member] | Domestic All-Cap/Large Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		60.00%
Maximum [Member] | Domestic Mid-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		25.00%
Maximum [Member] | Domestic Small-Cap Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		30.00%
Maximum [Member] | International Equity [Member]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Target Plan Asset Allocations		30.00%
Group Retiree Medical Insurance Contract [Member] | Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		$ 40.2
Fair Value of Plan Assets, Ending		36		40.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		40.2
Group Retiree Medical Insurance Contract [Member] | Other Postretirement Benefits Plan [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 (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		0
Group Retiree Medical Insurance Contract [Member] | Other Postretirement Benefits Plan [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		40.2
Fair Value of Plan Assets, Ending		36		$ 40.2
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Fair Value of Plan Assets, Beginning		$ 40.2
[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 $35.4 million, $32.9 million and $22.5 million of net periodic benefit cost recognized in 2018, 2017 and 2016, respectively, OG&E recognized the following: •a change in pension expense in 2018, 2017 and 2016 of $(14.1) million, $(2.3) million and $9.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1); •an increase in postretirement medical expense in 2018, 2017 and 2016 of $4.4 million, $6.2 million and $7.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and •a deferral of pension expense in 2018, 2017 and 2016 of $2.1 million, $1.1 million and $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $26.1 million, $15.3 million and $8.6 million, respectively, which are included in the Arkansas deferred pension expense regulatory asset (see Note 1).
[3]	GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.
[4]	This category represents U.S. Treasury notes and bonds with a Moody's Investors Service rating of Aaa and Government Agency Bonds with a Moody's Investors Service rating of A1 or higher.
[5]	This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.

Retirement Plans and Postreti_4

Retirement Plans and Postretirement Benefit Plans Postretirement Benefit Plans (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Employer contributions		$ 15		$ 20
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Settlement		26.1		15.3	$ 8.6
Net periodic benefit cost		35.4		32.9	22.5
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Level 3 Asset Value, Beginning of Period		40.2
Interest income		0.7
Dividend income		0.5
Unrealized gains		(0.5)
Realized losses		(0.2)
Administrative expenses and charges		(0.1)
Claims paid		(4.6)
Level 3 Asset Value, End of Period		36		40.2
Postretirement Plan, Expected Future Benefit Payments, Next Twelve Months		11.6
Postretirement Plan, Expected Future Benefit Payments, Year Two		11.6
Postretirement Plan, Expected Future Benefit Payments, Year Three		11.6
Postretirement Plan, Expected Future Benefit Payments in Year Four		11.6
Postretirement Plan, Expected Future Benefit Payments, Year Five		10.2
Postretirement Plan, Expected Future Benefit Payments, Five Fiscal Years Thereafter		46.7
Postemployment Benefits Liability		1.9		2.5
Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		0.5
Fair Value of Plan Assets, Ending				0.5
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, Beginning		0.5
Fair Value of Plan Assets, Ending				0.5
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, Beginning		0
Fair Value of Plan Assets, Ending				0
Pension Plan [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		687.5		672.2
Service cost		14.9		15.5	15.8
Interest cost		23.8		26.2	25.5
Plan settlements		(73.7)		(50.2)
Actuarial gains (losses)		(22)		38.6
Benefit Obligation, Ending		615.9		687.5	672.2
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		635.3		595.9
Actual return on plans' assets		(39.2)		84.4
Employer contributions		15		20
Plan settlements		(73.7)		(50.2)
Fair Value of Plan Assets, Ending		522.8		635.3	595.9
Funded Status of Plan		(93.1)		(52.2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		14.9		15.5	15.8
Interest cost		23.8		26.2	25.5
Expected return on plan assets		(44.1)		(42.6)	(41.5)
Amortization of unrecognized prior service cost		0		(0.1)	(0.1)	[1]
Settlement		25.1		15.3	0
Net periodic benefit cost		35.9		31.7	16.2
Amount paid by unconsolidated affiliates		2.5		4.3	5.1
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]	33.4		27.4	11.1
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Capitalized Portion of Net Periodic Benefit Cost		$ 3.8		$ 4.4	$ 4
Assumptions Used Calculating Benefit Obligation, Discount Rate		4.20%		3.60%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.73%		4.00%	4.00%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		7.50%		7.50%	7.50%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		4.20%		4.20%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		4.20%		4.20%	4.20%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ (14.6)		$ (14.8)
Pension Plan [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
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation, Beginning		149.4		215.9
Service cost		0.3		0.6	0.8
Interest cost		5.4		7.2	9.5
Plan settlements		0		(28.1)
Actuarial gains (losses)		(9.6)		5.6
Benefit Obligation, Ending		135.8		149.4	215.9
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		50.2		53.1
Actual return on plans' assets		(0.6)		2.8
Employer contributions		5.4		34.6
Plan settlements		0		(28.1)
Fair Value of Plan Assets, Ending		45.3		50.2	53.1
Funded Status of Plan		(90.5)		(99.2)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0.3		0.6	0.8
Interest cost		5.4		7.2	9.5
Expected return on plan assets		(2)		(2.2)	(2.3)
Amortization of unrecognized prior service cost		(8.4)		(3.5)	(8.8)	[1]
Settlement		0		0.6	0
Net periodic benefit cost		(0.9)		4.7	1.8
Amount paid by unconsolidated affiliates		(0.5)		0.3	0.2
Net Periodic Benefit Cost, Net of Unconsolidated Affiliates	[2]	(0.4)		4.4	1.6
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Capitalized Portion of Net Periodic Benefit Cost		$ 0.2		$ 1.2	$ 0.8
Assumptions Used Calculating Benefit Obligation, Discount Rate		4.30%		3.70%	4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.70%		4.20%	4.25%
Health Care Cost Trend Rate Assumed for Next Fiscal Year		7.25%
Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets		4.00%		4.00%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase					4.20%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				4.20%	4.20%
Defined Benefit Plan, Benefit Obligation, Benefits Paid		$ (13.5)		$ (15.7)
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		40.2
Fair Value of Plan Assets, Ending		36		40.2
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		9.5
Fair Value of Plan Assets, Ending		8.9		9.5
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		0.9
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		10
Fair Value of Plan Assets, Ending		9.8		10
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		0
Fair Value of Plan Assets, Ending		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		9.5
Fair Value of Plan Assets, Ending		8.9		9.5
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		0.9
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		40.2
Fair Value of Plan Assets, Ending		36		40.2
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		40.2
Fair Value of Plan Assets, Ending		36		40.2
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] | Cash [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Ending		0
Other Postretirement Benefit Plans, Defined Benefit [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning		50.2
Fair Value of Plan Assets, Ending		45.8		50.2
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		4.4		6.2	$ 7.9
Equity Funds [Member] | Pension Plan [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets, Beginning	[3]	29.9
Fair Value of Plan Assets, Ending	[3]	19.7	[4]	29.9
Equity Funds [Member] | Pension Plan [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]	0
Fair Value of Plan Assets, Ending	[3]	0		0
Equity Funds [Member] | Pension Plan [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
[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 $35.4 million, $32.9 million and $22.5 million of net periodic benefit cost recognized in 2018, 2017 and 2016, respectively, OG&E recognized the following: •a change in pension expense in 2018, 2017 and 2016 of $(14.1) million, $(2.3) million and $9.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory asset or liability (see Note 1); •an increase in postretirement medical expense in 2018, 2017 and 2016 of $4.4 million, $6.2 million and $7.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory asset or liability (see Note 1); and •a deferral of pension expense in 2018, 2017 and 2016 of $2.1 million, $1.1 million and $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $26.1 million, $15.3 million and $8.6 million, respectively, which are included in the Arkansas deferred pension expense regulatory asset (see Note 1).
[3]	This category represents units of participation in a commingled fund that primarily invested in stocks of international companies and emerging markets.
[4]	GAAP allows the measurement of certain investments that do not have a readily determinable fair value at the net asset value. These investments do not consider the observability of inputs; therefore, they are not included within the fair value hierarchy.

Report of Business Segments (De

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating revenues	$ 511.8	$ 698.8	$ 567	$ 492.7	$ 501.9	$ 716.8	$ 586.4	$ 456	$ 2,270.3	$ 2,261.1		$ 2,259.2
Cost of sales									892.5	897.6		880.1
Other operation and maintenance									474.6	458.7		438.1
Depreciation and amortization									321.6	283.5		322.6
Taxes other than income									92	89.4		87.6
Operating income (loss)	58	227.3	137.7	66.6	85.7	249.1	147.3	49.8	489.6	531.9		530.8
Equity in earnings of unconsolidated affiliates									152.8	131.2		101.8
Other income (expense)									11.3	50.4		(4.2)
Interest expense									156	143.8		142.1
Income tax expense (benefit)									72.2	(49.3)	[1]	148.1
NET INCOME	54.7	$ 205.1	$ 110.7	$ 55	294.8	$ 183.4	$ 104.8	$ 36	425.5	619		338.2
Investment in unconsolidated affiliates	1,177.5				1,160.4				1,177.5	1,160.4		1,158.6
Total assets	10,748.6				10,412.7				10,748.6	10,412.7		9,939.6
Capital expenditures									573.6	824.1		660.1
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues									2,270.3	2,261.1		2,259.2
Cost of sales									892.5	897.6		880.1
Other operation and maintenance									473.8	469.8		451.2
Depreciation and amortization									321.6	280.9		316.4
Taxes other than income									88.2	84.8		84
Operating income (loss)									494.2	528		527.5
Equity in earnings of unconsolidated affiliates									0	0		0
Other income (expense)									25.6	57.7		9.1
Interest expense									151.8	138.4		138.1
Income tax expense (benefit)									40	141.8	[1]	114.4
NET INCOME									328	305.5		284.1
Investment in unconsolidated affiliates	0				0				0	0		0
Total assets	9,704.5				9,255.6				9,704.5	9,255.6		8,669.4
Capital expenditures									573.6	824.1		660.1
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									1.4	(0.8)		(0.1)
Depreciation and amortization									0	0		0
Taxes other than income									0.6	1		0
Operating income (loss)									(2)	(0.2)		0.1
Equity in earnings of unconsolidated affiliates									152.8	131.2		101.8
Other income (expense)									(4.9)	(1)		(7.7)
Interest expense									0	0		0
Income tax expense (benefit)									37.1	(195.2)	[1]	40.5
NET INCOME									108.8	325.2		53.7
Investment in unconsolidated affiliates	1,166.6				1,151.9				1,166.6	1,151.9		1,158.6
Total assets	1,169.8				1,155.3				1,169.8	1,155.3		1,521.6
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									(0.6)	(10.3)		(13)
Depreciation and amortization									0	2.6		6.2
Taxes other than income									3.2	3.6		3.6
Operating income (loss)									(2.6)	4.1		3.2
Equity in earnings of unconsolidated affiliates									0	0		0
Other income (expense)									(3.4)	(5.4)		(5.4)
Interest expense									10.2	6.3		4.2
Income tax expense (benefit)									(4.9)	4.1	[1]	(6.8)
NET INCOME									(11.3)	(11.7)		0.4
Investment in unconsolidated affiliates	10.9				8.5				10.9	8.5		0
Total assets	184.8				109.1				184.8	109.1		89
Capital expenditures									0	0		0
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		0
Other income (expense)									(6)	(0.9)		(0.2)
Interest expense									(6)	(0.9)		(0.2)
Income tax expense (benefit)									0	0	[1]	0
NET INCOME									0	0		0
Investment in unconsolidated affiliates	0				0				0	0		0
Total assets	$ (310.5)				$ (107.3)				(310.5)	(107.3)		(340.4)
Capital expenditures									$ 0	0		$ 0
Tax Benefit Due to Tax Law Change [Member]
Segment Reporting Information [Line Items]
Income tax expense (benefit)										245.2
Tax Expense Due to Tax Law Change [Member]
Segment Reporting Information [Line Items]
Income tax expense (benefit)										$ 10.5
[1]	The Company recorded an income tax benefit of $245.2 million and income tax expense of $10.5 million during the fourth quarter of 2017 due to the Company remeasuring deferred taxes related to the natural gas midstream operations and other operations segments, respectively, as a result of the 2017 Tax Act. See Note 8 for further discussion of the effects of the 2017 Tax Act.

Commitments and Contingencies_2

Commitments and Contingencies (Details) $ in Millions		12 Months Ended
		Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Feb. 01, 2019USD ($)
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		$ 22.1
Operating Leases, Future Minimum Payments, Due in Two Years		3.9
Operating Leases, Future Minimum Payments, Due in Three Years		3.5
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		37.6
Operating Leases, Future Minimum Payments Due		72.9
Operating Leases, Rent Expense, Net		4.9	$ 6.2	$ 9.3
Purchase Obligation, Due in Next Twelve Months		198
Unrecorded Unconditional Purchase Obligation, Due within Two Years		104.1
Unrecorded Unconditional Purchase Obligation, Due within Three Years		104.1
Unrecorded Unconditional Purchase Obligation, Due within Four Years		104.5
Unrecorded Unconditional Purchase Obligation, Due within Five Years		117
Long-term Purchase Commitment, Amount		627.7
Utilities Operating Expense, Purchased Power under Long-term Contracts		57.6	61.1	61
OG&E Railcar Lease Agreement [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		18.6
Operating Leases, Future Minimum Payments, Due in Two Years		0
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		18.6
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		2.9
Operating Leases, Future Minimum Payments, Due in Three Years		2.9
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		37.6
Operating Leases, Future Minimum Payments Due		51.7
OGE Energy Building Lease [Member]
Loss Contingencies [Line Items]
Operating Leases, Future Minimum Payments Due, Next Twelve Months		1
Operating Leases, Future Minimum Payments, Due in Two Years		1
Operating Leases, Future Minimum Payments, Due in Three Years		0.6
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		2.6
OG&E cogeneration capacity and fixed operation and maintenance payments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	[1]	10.9
Unrecorded Unconditional Purchase Obligation, Due within Two Years	[1]	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	[1]	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	[1]	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	[1]	0
Long-term Purchase Commitment, Amount	[1]	10.9
OG&E expected cogeneration energy payments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months	[1]	2.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	[1]	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	[1]	0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	[1]	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	[1]	0
Long-term Purchase Commitment, Amount	[1]	2.4
OG&E minimum fuel purchase commitments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months		75.8
Unrecorded Unconditional Purchase Obligation, Due within Two Years		44.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years		44.6
Unrecorded Unconditional Purchase Obligation, Due within Four Years		44.6
Unrecorded Unconditional Purchase Obligation, Due within Five Years		44.6
Long-term Purchase Commitment, Amount		254.2
OG&E expected wind purchase commitments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months		56.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years		56.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years		57.1
Unrecorded Unconditional Purchase Obligation, Due within Four Years		57.5
Unrecorded Unconditional Purchase Obligation, Due within Five Years		58
Long-term Purchase Commitment, Amount		285.8
OG&E long-term service agreement commitments [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months		46.8
Unrecorded Unconditional Purchase Obligation, Due within Two Years		2.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years		2.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years		2.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years		14.4
Long-term Purchase Commitment, Amount		68.4
Environmental compliance plan expenditures [Member]
Loss Contingencies [Line Items]
Purchase Obligation, Due in Next Twelve Months		5.8
Unrecorded Unconditional Purchase Obligation, Due within Two Years		0.2
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		$ 6
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		$ 112.4	115.2	124.8
OG&E capacity payments [Member]
Loss Contingencies [Line Items]
Long-term Purchase Commitment, Amount		60	63	66.3
CPV Keenan [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts		27	29	29.2
Edison Mission Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts		21.7	22.1	21.1
FPL Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	[2]	2.1	2.6	3.4
NextEra Energy [Member]
Loss Contingencies [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts		$ 6.8	$ 7.4	$ 7.3
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
Maximum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Maximum		$ 16.2			$ 6.8
[1]	Cogeneration capacity, fixed operation and maintenance and energy payments will end in 2019, as a result of contract expiration. As described below, OG&E intends to acquire the AES and Oklahoma Cogeneration LLC power plants, pending regulatory approval.
[2]	OG&E's purchased power contract with FPL Energy for 50 MWs expired in 2018.

Rate Matters and Regulation (De

Rate Matters and Regulation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Public Utilities, Approved Rate Increase (Decrease), Amount		$ (64)
Public Utilities, Approved Return on Equity, Percentage		9.50%
Public Utilities, Approved Equity Capital Structure, Percentage		53.00%
Customer Refund Liability, Current		$ 0.3	$ 1.7
Interim Rate Revenue Reserved		$ 15.4
Public Utilities, Approved Debt Capital Structure, Percentage		47.00%
Regulatory Assets, Current		$ 18.5	40.8
Recommended Disallowance for Fuel Adjustment		3.3
Refund for Fuel Adjustment		2.4
Public Utilities, Amount Requested for Acquisition		$ 53.5
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%
Dry Scrubber Project [Member]
Estimated Environmental Capital Costs		$ 520
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		504.3
OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount		77.6
Customer Refund Liability, Current		18.9
Interim Rate Revenue Reserved		5.6
ARKANSAS
Public Utilities, Requested Rate Increase (Decrease), Amount		6.4
Public Utilities, Approved Rate Increase (Decrease), Amount		(3.3)
Customer Refund Liability, Current		7.7
Oklahoma demand program rider under recovery [Member]
Regulatory Assets, Current	[1]	6.4	$ 31.6
January 16, 2018 [Member] | OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 1.9
Public Utilities, Requested Return on Equity, Percentage		9.90%
FERC [Member]
Recommended Common Equity Percentage		7.85%
Public Utilities, Approved Return on Equity, Percentage		10.60%
Revenue impact of recommended change in return on common equity		$ 1.5
[1]	Included in Other Current Assets on the Consolidated Balance Sheets.

Quarterly Financial Data (Detai

Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Operating revenues	$ 511.8		$ 698.8		$ 567		$ 492.7		$ 501.9		$ 716.8		$ 586.4		$ 456		$ 2,270.3		$ 2,261.1		$ 2,259.2
Operating income	58		227.3		137.7		66.6		85.7		249.1		147.3		49.8		489.6		531.9		530.8
Net income	$ 54.7		$ 205.1		$ 110.7		$ 55		$ 294.8		$ 183.4		$ 104.8		$ 36		$ 425.5		$ 619		$ 338.2
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.27	[1]	$ 1.03	[1]	$ 0.55	[1]	$ 0.28	[1]	$ 1.48	[1]	$ 0.92	[1]	$ 0.52	[1]	$ 0.18	[1]	$ 2.13	[1]	$ 3.10	[1]	$ 1.69
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.27	[1]	$ 1.02	[1]	$ 0.55	[1]	$ 0.27	[1]	$ 1.48	[1]	$ 0.92	[1]	$ 0.52	[1]	$ 0.18	[1]	$ 2.12	[1]	$ 3.10	[1]	$ 1.69
[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, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance		$ 1.5	$ 1.5	$ 1.4
Valuation Allowances and Reserves, Charged to Cost and Expense		1.6	2.6	2.5
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	[1]	1.4	2.6	2.4
Valuation Allowances and Reserves, Ending Balance		$ 1.7	$ 1.5	$ 1.5
[1]	Uncollectible accounts receivable written off, net of recoveries.