View Filing Data

Print Document View Excel Document

Document and Entity Information Document	3 Months Ended
Document and Entity Information Document	Mar. 31, 2016 shares
Document Information [Line Items]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	0001021635
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,701,852

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OPERATING REVENUES
OPERATING REVENUES	$ 433.1	$ 480.1
COST OF SALES
COST OF SALES	177.9	211.6
OPERATING EXPENSES
Other operation and maintenance	113.9	111.7
Depreciation and amortization	78.5	75.9
Taxes other than income	24.9	24.5
Total operating expenses	217.3	212.1
OPERATING INCOME	37.9	56.4
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	28.3	31.7
Allowance for equity funds used during construction	1.6	1.5
Other income	5.6	4.9
Other expense	(1.7)	(1.0)
Net other income	33.8	37.1
INTEREST EXPENSE
Interest on long-term debt	35.8	36.9
Allowance for borrowed funds used during construction	(0.9)	(0.8)
Interest on short-term debt and other interest charges	1.4	1.3
Interest expense	36.3	37.4
INCOME BEFORE TAXES	35.4	56.1
INCOME TAX EXPENSE	10.2	12.9
NET INCOME	$ 25.2	$ 43.2
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7	199.5
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.7	199.5
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.13	$ 0.22
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.13	0.22
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.27500	$ 0.25000

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Net income	$ 25.2	$ 43.2
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4 and $0.8, respectively	0.8	0.4
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.0 and $0.2, respectively	0.0	0.2
Amortization of prior service cost, net of tax of ($0.2) and ($0.3), respectively	(0.4)	(0.4)
Other comprehensive income, net of tax	0.4	0.2
Comprehensive income	$ 25.6	$ 43.4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Parenthetical - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.4	$ 0.8
Postretirement plans:
Amortization of deferred net loss	0.0	0.2
Amortization of prior service cost	$ (0.2)	$ (0.3)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 25.2	$ 43.2
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	78.5	75.9
Deferred income taxes and investment tax credits	10.4	13.0
Equity in earnings of unconsolidated affiliates	(28.3)	(31.7)
Distributions from unconsolidated affiliates	28.7	34.3
Allowance for equity funds used during construction	(1.6)	(1.5)
Stock-based compensation	1.7	0.5
Regulatory assets	(2.3)	2.7
Regulatory liabilities	(4.6)	(0.7)
Other assets	2.5	(0.8)
Other liabilities	2.1	(0.1)
Change in certain current assets and liabilities
Accounts receivable, net	38.0	19.6
Accounts receivable - unconsolidated affiliates	(1.2)	(1.0)
Accrued unbilled revenues	2.1	9.0
Fuel, materials and supplies inventories	10.2	(23.9)
Fuel clause under recoveries	0.0	41.3
Other current assets	(10.0)	1.3
Accounts payable	(44.1)	(15.1)
Fuel clause over recoveries	2.0	0.0
Other current liabilities	(35.9)	(26.4)
Net Cash Provided from Operating Activities	73.4	139.6
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(177.7)	(108.8)
Return of capital - equity method investments	6.6	0.0
Proceeds from sale of assets	0.0	0.1
Net Cash Used in Investing Activities	(171.1)	(108.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock	0.0	3.1
Dividends paid on common stock	(54.9)	(49.9)
Payment of long-term debt	(110.1)	0.0
Increase in short-term debt	187.5	11.9
Net Cash Provided from (Used in) Financing Activities	22.5	(34.9)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(75.2)	(4.0)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2	5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0.0	$ 1.5

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 0.0	$ 75.2
Accounts receivable, less reserve of $1.0 and $1.4, respectively	135.1	173.1
Accounts receivable - unconsolidated affiliates	2.9	1.7
Accrued unbilled revenues	51.4	53.5
Income taxes receivable	17.4	17.2
Fuel inventories	105.4	113.8
Materials and supplies, at average cost	78.3	80.1
Other	65.4	55.6
Total current assets	455.9	570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,187.4	1,194.4
Other	69.5	70.7
Total other property and investments	1,256.9	1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,415.7	10,318.3
Construction work in progress	300.1	278.5
Total property, plant and equipment	10,715.8	10,596.8
Less accumulated depreciation	3,328.3	3,274.4
Net property, plant and equipment	7,387.5	7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	402.8	402.2
Other	20.2	20.7
Total deferred charges and other assets	423.0	422.9
TOTAL ASSETS	9,523.3	9,580.6
CURRENT LIABILITIES
Short-term debt	187.5	0.0
Accounts payable	172.7	262.5
Dividends payable	54.9	54.9
Customer deposits	77.9	77.0
Accrued taxes	24.7	45.9
Accrued interest	32.9	42.9
Accrued compensation	55.6	54.4
Long-term debt due within one year	0.0	110.0
Fuel clause over recoveries	63.2	61.3
Other	37.1	43.9
Total current liabilities	706.5	752.8
LONG-TERM DEBT	2,629.3	2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	298.2	299.9
Deferred income taxes	2,188.1	2,178.2
Regulatory liabilities	278.3	273.6
Other	124.6	121.3
Total deferred credits and other liabilities	2,889.2	2,873.0
Total liabilities	6,225.0	6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,102.9	1,101.3
Retained earnings	2,230.1	2,259.8
Accumulated other comprehensive loss, net of tax	(34.7)	(35.1)
Total stockholders' equity	3,298.3	3,326.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 9,523.3	$ 9,580.6

CONDENSED CONSOLIDATED BALANCE SHEETS Parenthetical - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Allowance for Doubtful Accounts Receivable	$ 1.0	$ 1.4

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2014	$ 3,244.4	$ 2.0	$ 1,085.6	$ 2,198.2	$ (41.4)
Comprehensive income (loss)
Net income	43.2	0.0	0.0	43.2	0.0
Other comprehensive income, net of tax	0.2	0.0	0.0	0.0	0.2
Dividends declared on common stock	(49.9)	0.0	0.0	(49.9)	0.0
Issuance of common stock	3.2	0.0	3.2	0.0	0.0
Stock-based compensation	0.7	0.0	0.7	0.0	0.0
Balance at Mar. 31, 2015	3,241.8	2.0	1,089.5	2,191.5	(41.2)
Balance at Dec. 31, 2015	3,326.0	2.0	1,099.3	2,259.8	(35.1)
Comprehensive income (loss)
Net income	25.2	0.0	0.0	25.2	0.0
Other comprehensive income, net of tax	0.4	0.0	0.0	0.0	0.4
Dividends declared on common stock	(54.9)	0.0	0.0	(54.9)	0.0
Stock-based compensation	1.6	0.0	1.6	0.0	0.0
Balance at Mar. 31, 2016	$ 3,298.3	$ 2.0	$ 1,100.9	$ 2,230.1	$ (34.7)

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Summary of Significant Accounting Policies

Organization

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and lacks the power to direct activities that most significantly impact economic performance.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

The natural gas midstream operations segment represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns a crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company's contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by CenterPoint and the Company, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2016 and December 31, 2015, the results of its operations and cash flows for the three months ended March 31, 2016 and 2015, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2015 Form 10-K.

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.

Certain prior year amounts have been reclassified to conform with the current year presentation.

OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates.

The following table is a summary of OG&E's regulatory assets and liabilities at:



(In millions)	March 31, 2016		December 31, 2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	37.4	$	36.6
Other (A)	13.4		9.9
Total Current Regulatory Assets	$	50.8	$	46.5
Non-Current
Benefit obligations regulatory asset	$	240.0	$	242.2
Income taxes recoverable from customers, net	56.8		56.7
Smart Grid	43.6		43.6
Deferred storm expenses	30.9		27.6
Unamortized loss on reacquired debt	14.4		14.8
Other	17.1		17.3
Total Non-Current Regulatory Assets	$	402.8	$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	63.2	$	61.3
Other (B)	3.7		7.5
Total Current Regulatory Liabilities	$	66.9	$	68.8
Non-Current
Accrued removal obligations, net	$	255.3	$	254.9
Pension tracker	22.0		17.7
Other (C)	1.0		1.0
Total Non-Current Regulatory Liabilities	$	278.3	$	273.6


(A)	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.


(B)	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.


(C)	Prior year amount of $1.0 million reclassified from deferred other liabilities to Non-Current Regulatory Liabilities.

Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

The following table summarizes changes to the Company's asset retirement obligations during the three months ended March 31, 2016 and 2015.



	Three Months Ended March 31,
(In millions)	2016		2015
Balance at January 1	$	63.3	$	58.6
Accretion expense	0.7		0.6
Liabilities settled	—		(0.3		)
Balance at March 31	$	64.0	$	58.9

Comprehensive Income (Loss) Note [Text Block]

Accumulated Other Comprehensive Income (Loss)

The following tables summarize changes in the components of accumulated other comprehensive income (loss) during the three months ended March 31, 2016 and 2015. All amounts below are presented net of tax.



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Net loss		Prior service cost			Total
Balance at December 31, 2015	$	(39.2	)	$	0.1	$	2.5	$	1.5		$	(35.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.8			—		—		(0.4		)	0.4
Balance at March 31, 2016	$	(38.4	)	$	0.1	$	2.5	$	1.1		$	(34.7	)



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1	$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.4			—		0.2			(0.4		)	0.2
Balance at March 31, 2015	$	(36.4	)	$	0.1	$	(7.8	)	$	2.9		$	(41.2	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three months ended March 31, 2016 and 2015.



Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended March 31,
(In millions)	2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.2	)	$	(1.2	)	(A)
	(0.4		)	(0.8		)	Tax benefit
	$	(0.8	)	$	(0.4	)	Net of tax

Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.4	)	(A)
Prior service cost	0.6			0.7			(A)
	0.6			0.3			Total before tax
	0.2			0.1			Tax expense
	$	0.4		$	0.2		Net of tax

Total reclassifications for the period	$	(0.4	)	$	(0.2	)	Net of tax


(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Reclassifications [Text Block]

Reclassifications

Prior periods have been adjusted for the reclassification of $16.8 million of debt issuance costs from total deferred charges and other assets to Long-Term Debt in the Condensed Consolidated Balance Sheets to be consistent with the 2016 presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," as of March 31, 2016.

- Definition

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e689-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=36458714&loc=SL7669619-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e640-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e716-108580

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e709-108580

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e637-108580

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e681-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

+ Details

Accounting Pronouncements	3 Months Ended
Accounting Pronouncements	Mar. 31, 2016
Accounting Pronouncement [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	Accounting Pronouncements Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. The deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has yet to select a transition method or determine the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material. Consolidation. In February 2015, the FASB issued ASU 2015-02, "Consolidation (Topic 810)". The amendments in ASU 2015-02 affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. The new standard modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities along with eliminating the presumption that a general partner should consolidate a limited partnership. The new standard is effective for fiscal years beginning after December 15, 2015. The adoption of this new standard did not result in the consolidation of any non-consolidated entities. Leases. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842)”. The main difference between current lease accounting and Topic 842 is the recognition of right-to-use assets and lease liabilities by lessees for those leases classified as operating leases under current accounting guidance. Lessees, such as the Company, will need to recognize a right-of-use asset and a lease liability for virtually all of their leases, other than leases that meet the definition of a short-term lease. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the Topic 842 retains a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense, while finance leases will result in a front-loaded expense pattern, similar to current capital leases. Classification of operating and finance leases will be based on criteria that are largely similar to those applied in current lease guidance, but without the explicit thresholds. The new guidance is effective for fiscal years beginning after December 2018. The new guidance must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Company has not determined the impact on its Condensed Consolidated Financial Statements, but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Investments. In March 2016, the FASB issued ASU 2016-07, "Investments-Equity Method and Joint Ventures; Simplifying the Transition to the Equity Method of Accounting (Topic 323)." The amendments in ASU 2016-07 eliminate the requirement to retroactively adopt the equity method of accounting for a qualifying equity method investment. ASU 2016-07 requires equity method investors to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for equity method accounting. The amendments in this ASU are effective for the fiscal years and interim periods within those fiscal years, beginning after December 15, 2016. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements. Employee Share Based Payment Accounting. In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends ASC Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements. The new guidance among other requirements will require all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Currently, tax benefits in excess of compensation cost (“windfalls”) are recorded in equity, and tax deficiencies (“shortfalls”) are recorded in equity to the extent of previous windfalls, and then to the income statement. This change is required to be applied prospectively to all excess tax benefits and tax deficiencies resulting from settlements after the date of adoption of the ASU2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. Early adoption will be permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. The Company has not determined the impact on its Condensed Consolidated Financial Statements, however, the impact is not expected to be material.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e725-108305

+ Details

Investment in Unconsolidated Affiliate and Related Party Transactions

3 Months Ended

Mar. 31, 2016

Schedule of Equity Method Investments [Line Items]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Investment in Unconsolidated Affiliate

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. 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 adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheets at March 31, 2016. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from Enable, which do not exceed cumulative equity in earnings subsequent to the date of investment, to be a return on investment which are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment which are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.

Investment in Unconsolidated Affiliate and Related Party Transactions

On March 14, 2013, the Company entered into a Master Formation Agreement with the ArcLight group and CenterPoint pursuant to which the Company, the ArcLight group and CenterPoint, agreed to form Enable to own and operate the midstream businesses of the Company and CenterPoint that was initially structured as a private limited partnership. This transaction closed on May 1, 2013.

Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed 100 percent of the equity interests in Enogex LLC to Enable. The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost.

In April 2014, Enable completed an initial public offering of 25.0 million common units resulting in Enable becoming a publicly traded Master Limited Partnership. At March 31, 2016, the Company owned 111.0 million common units, or 26.3 percent, of which 68.2 million units were subordinated.

CenterPoint and the Company also own a 40 percent and 60 percent interest, respectively, in any incentive distribution rights to be held by the general partner of Enable following the initial public offering.

Distributions received from Enable were $35.3 million and $34.3 million during the three months ended March 31, 2016 and 2015, respectively.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below. The Company's interest in Enogex Holdings was deconsolidated on May 1, 2013.

On May 1, 2013, the Company and Enable entered into a Services Agreement, Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. Under these agreements, the Company charged operating costs to Enable of $1.3 million and $2.8 million for three months ended March 31, 2016 and 2015, 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.

Additionally, the Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, CenterPoint, the Company and Enable agreed to continue the secondment to Enable for 192 employees that participate in the Company's defined benefit and retirement plans, beyond December 31, 2014. The Company billed Enable for reimbursement of $7.1 million and $10.0 million in the three months ended March 31, 2016 and 2015, respectively, under the Transitional Seconding Agreement for employment costs.

The Company had accounts receivable from Enable of $2.9 million as of March 31, 2016 and $1.7 million as of December 31, 2015, for amounts billed for transitional services, including the cost of seconded employees.

Related Party Transactions with Enable

OG&E entered into a contract with Enable to provide gas transportation services effective May 1, 2014. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries. The following table summarizes related party transactions between OG&E and Enable during the three months ended March 31, 2016, and 2015.



	Three Months Ended March 31,
(In millions)	2016		2015
Operating Revenues:
Electricity to power electric compression assets	$	2.3	$	3.1
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.8
Natural gas purchases/(sales)	1.5		2.5

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below as of March 31, 2016 and December 31, 2015.



Balance Sheet	March 31,		December 31,
(In millions)	2016		2015
Current assets	$	379	$	381
Non-current assets	10,870		10,857
Current liabilities	279		615
Non-current liabilities	3,123		3,092



Income Statement	Three Months Ended March 31,
(In millions)	2016		2015
Operating revenues	$	509	$	616
Cost of NGLs	195		292
Operating income	103		104
Net income	86		91

The formation of Enable was considered a business combination, and CenterPoint was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint for Enogex Holdings is allocated to the assets acquired and liabilities assumed on May 1, 2013 based on their fair value. Enogex Holdings' assets, liabilities and equity have accordingly been adjusted to estimated fair value as of May 1, 2013, resulting in an increase to Enable's equity of $2.2 billion. Due to the contribution of Enogex LLC to Enable meeting the requirements of being in substance real estate and the recording the initial investment at historical cost, the effects of the amortization and depreciation expense associated with the fair value adjustments on Enable's results of operations have been eliminated in the Company's recording of its equity in earnings of Enable.

The Company recorded equity in earnings of unconsolidated affiliates of $28.3 million and $31.7 million for the three months ended March 31, 2016 and 2015, 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 net assets of Enable. The basis difference is the result of the initial contribution of Enogex LLC to Enable in May 2013, and subsequent issuances of equity by Enable, including the initial public offering in April 2014 and the issuance of common units for the acquisition of CenterPoint's 24.95 percent interest in Southeast Supply Header, LLC. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above.

The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was $775.5 million as of March 31, 2016.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three months ended March 31, 2016 and 2015.



	Three Months Ended March 31,
(In millions)	2016		2015
OGE's share of Enable Net Income	$	21.3	$	23.8
Amortization of basis difference	2.9		3.5
Elimination of Enogex Holdings fair value and other adjustments	4.1		4.4
Equity in earnings of unconsolidated affiliates	$	28.3	$	31.7

Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

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 March 31, 2016 and December 31, 2015, except for long-term debt which is recorded at the carrying amount.

The following table summarizes the fair value and carrying amount of the Company's long-term debt at March 31, 2016 and December 31, 2015.



	March 31, 2016				December 31, 2015
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,384.3	$	2,748.1	$	2,493.9	$	2,754.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.0		9.5		10.0		9.2
OGE Energy Senior Notes	99.6		99.9		99.5		99.9

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 in which fair value was 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.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Stock Based Compensation

3 Months Ended

Mar. 31, 2016

Stock-Based Compensation [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the three months ended March 31, 2016, and 2015 related to the Company's performance units and restricted stock.



	Three Months Ended March 31,
(In millions)	2016		2015
Performance units
Total shareholder return	$	1.1	$	1.9
Earnings per share	0.6		0.5
Total performance units	1.7		2.4
Restricted stock	—		—
Total compensation expense	1.7		2.4
Less: Amount paid by unconsolidated affiliates	—		0.3
Net compensation expense	$	1.7	$	2.1
Income tax benefit	$	0.6	$	0.8

The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units. During the three months ended March 31, 2016, there were no shares of new common stock issued pursuant to the Company's Stock Incentive Plan related to restricted stock grants (net of forfeitures) and payouts of earned performance units. During the three months ended March 31, 2016, there were 901 shares of restricted stock returned to the Company to satisfy tax liabilities.

The following table summarizes the activity of the Company's stock-based compensation during the three months ended March 31, 2016.



	Units/Shares	Fair Value Per Share
Grants
Performance units (Total shareholder return)	280,604	$	20.84
Performance units (Earnings per share)	93,533	$	26.59

Income Taxes	3 Months Ended
Income Taxes	Mar. 31, 2016
Income Taxes [Abstract]
Income Tax Disclosure [Text Block]	Income Taxes The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2012 or state and local tax examinations by tax authorities for years prior to 2011. 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. In addition, OG&E and Enable earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.

Common Equity

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three months ended March 31, 2016. The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan or purchase shares traded on the open market. At March 31, 2016, there were 4,774,442 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings Per Share

Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units. Basic and diluted earnings per share for the Company were calculated as follows:



	Three Months Ended March 31,
(In millions)	2016		2015
Net Income	$	25.2	$	43.2
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.5
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—		—
Diluted average common shares outstanding	199.7		199.5
Basic Earnings Per Average Common Share	$	0.13	$	0.22
Diluted Earnings Per Average Common Share	$	0.13	$	0.22
Anti-dilutive shares excluded from earnings per share calculation	—		—

Long-Term Debt

3 Months Ended

Mar. 31, 2016

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

At March 31, 2016, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds on any business day. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:



SERIES			DATE DUE	AMOUNT
				(In millions)
0.05%	-	0.39%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.43%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.40%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds. As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as long-term debt in the Company's Condensed Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

Short-Term Debt and Credit Facilities

3 Months Ended

Mar. 31, 2016

Short-term Debt [Abstract]

Short-Term Debt and Credit Facilities

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. As of March 31, 2016, the Company had $187.5 million of short-term debt compared to no short-term debt at December 31, 2015, at a weighted-average interest rate of 0.74 percent. The following table provides information regarding the Company's revolving credit agreements and available cash at March 31, 2016.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	187.5	0.74	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0		1.7		0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0	$	189.2	0.95	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2016.


(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)	As of March 31, 2016, commitments of $16.3 million and $8.7 million of the Company's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.

OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $800.0 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.

Retirement Plans and Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2016

Retirement Plans and Postretirement Benefit Plans [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost, before consideration of capitalized amounts, of the Company's Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Consolidated Financial Statements are as follows:

Net Periodic Benefit Cost



	Pension Plan						Restoration of Retirement Income Plan				Postretirement Benefit Plans
	Three Months Ended March 31,						Three Months Ended March 31,				Three Months Ended March 31,
(In millions)	2016			2015			2016		2015		2016			2015
Service cost	$	4.4		$	4.5		$	0.1	$	0.4	$	0.3		$	0.5
Interest cost	6.6			6.4			0.1		0.2		2.3			2.6
Expected return on plan assets	(10.5		)	(11.8		)	—		—		(0.6		)	(0.6		)
Amortization of net loss	4.2			4.3			0.2		0.1		0.5			3.4
Amortization of unrecognized prior service cost (A)	—			0.1			—		—		(2.2		)	(4.1		)
Total net periodic benefit cost	4.7			3.5			0.4		0.7		0.3			1.8
Less: Amount paid by unconsolidated affiliates	1.3			1.1			—		—		0.1			0.3
Net periodic benefit cost (B)	$	3.4		$	2.4		$	0.4	$	0.7	$	0.2		$	1.5


(A)	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.


(B)	In addition to the $4.0 million and $4.6 million of net periodic benefit cost recognized during the three months ended March 31, 2016 and 2015, respectively, the Company recognized the following:


•	an increase in pension expense in the three months ended March 31, 2016 and 2015 of $2.3 million and $3.0 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and


•	an increase in postretirement medical expense in the three months ended March 31, 2016 and 2015 of $2.0 million and $1.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1).



	Three Months Ended
	March 31,
(In millions)	2016		2015
Capitalized portion of net periodic pension benefit cost	$	1.2	$	0.8
Capitalized portion of net periodic postretirement benefit cost	0.1		0.5

Report of Business Segments

3 Months Ended

Mar. 31, 2016

Segment Reporting Information [Line Items]

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.

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 three months ended March 31, 2016 and 2015.



Three Months Ended March 31, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	433.1	$	—		$	—		$	—		$	433.1
Cost of sales	177.9		—			—			—			177.9
Other operation and maintenance	116.3		0.2			(2.6		)	—			113.9
Depreciation and amortization	76.7		—			1.8			—			78.5
Taxes other than income	23.6		—			1.3			—			24.9
Operating income (loss)	38.6		(0.2		)	(0.5		)	—			37.9
Equity in earnings of unconsolidated affiliates	—		28.3			—			—			28.3
Other income (expense)	5.3		—			0.3			(0.1		)	5.5
Interest expense	35.5		—			0.9			(0.1		)	36.3
Income tax expense (benefit)	2.3		10.1			(2.2		)	—			10.2
Net income	$	6.1	$	18.0		$	1.1		$	—		$	25.2
Investment in unconsolidated affiliates	$	—	$	1,187.4		$	—		$	—		$	1,187.4
Total assets	$	8,288.5	$	1,467.9		$	98.7		$	(331.8	)	$	9,523.3



Three Months Ended March 31, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	480.1	$	—		$	—		$	—		$	480.1
Cost of sales	211.6		—			—			—			211.6
Other operation and maintenance	114.3		0.8			(3.4		)	—			111.7
Depreciation and amortization	73.8		—			2.1			—			75.9
Taxes other than income	23.1		—			1.4			—			24.5
Operating income (loss)	57.3		(0.8		)	(0.1		)	—			56.4
Equity in earnings of unconsolidated affiliates	—		31.7			—			—			31.7
Other income (expense)	2.9		—			2.5			—			5.4
Interest expense	36.8		—			0.6			—			37.4
Income tax expense (benefit)	6.3		8.1			(1.5		)	—			12.9
Net income	$	17.1	$	22.8		$	3.3		$	—		$	43.2
Investment in unconsolidated affiliates	$	—	$	1,315.7		$	—		$	—		$	1,315.7
Total assets	$	8,217.7	$	1,476.7		$	122.3		$	(332.4	)	$	9,484.3

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8906-108599

+ Details

Commitments and Contingencies	3 Months Ended
Commitments and Contingencies	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Except as set forth below, in Note 13 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 14 and 15 to the Company's Consolidated Financial Statements included in the Company's 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities. Environmental Laws and Regulations The activities of OG&E are subject to numerous stringent and complex Federal, state and local laws and regulations governing environmental protection. These laws and regulations can change, restrict or otherwise impact OG&E's business activities in many ways including the handling or disposal of waste material, future construction activities to avoid or mitigate harm to threatened or endangered species and requiring the installation and operation of emissions pollution control equipment. Failure to comply with these laws and regulations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. OG&E believes that its operations are in substantial compliance with current Federal, state and local environmental standards. Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to its condensed financial position or results of operations. The Company believes, however, that it is likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards is expected to increase the cost of conducting business. Management continues to evaluate its compliance with existing and proposed environmental legislation and regulations and implement appropriate environmental programs in a competitive market. OG&E is managing several significant uncertainties about the scope and timing for the acquisition, installation and operation of additional pollution control equipment and compliance costs for a variety of the EPA rules that are being challenged in court. OG&E is unable to predict the financial impact of these matters with certainty at this time. Federal Clean Air Act New Source Review Litigation As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants. On July 8, 2013, the U.S. Department of Justice filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint sought to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club intervened in this proceeding. On August 30, 2013, the government filed a Motion for Summary Judgment and on September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, the Court dismissed the complaints filed by the EPA and the Sierra Club. The Court held that it lacked subject matter jurisdiction over plaintiffs’ claims because plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution. The court also ruled in the alternative that, even if plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.” The EPA and the Sierra Club did not file an appeal of the Court's ruling. On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the District Court dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the District Court to dismiss its remaining claims with prejudice. On August 27, 2014, the District Court granted the Sierra Club's request. The Sierra Club appealed the District Court's dismissal of its prevention of significant deterioration claim to the United States Court of Appeals for the Tenth Circuit. On March 8, 2016, the Tenth Circuit affirmed the trial court's decision dismissing the Sierra Club's case. On March 21, 2016, the Sierra Club filed a request for rehearing en banc with the Tenth Circuit. On April 13, 2016, the Tenth Circuit denied the request for rehearing. OG&E cannot predict whether the Sierra Club will seek review of the case by the United States Supreme Court. Air Quality Control System On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating dry scrubber systems to be installed at Sooner Units 1 and 2. OG&E entered into an agreement on February 9, 2015, to install the dry scrubber systems. The dry scrubbers are scheduled to be completed by 2019. More detail regarding the dry scrubber project can be found under the “Pending Regulatory Matters” in Note 13. Other In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other experts to assess the claim. If, in management's opinion, the Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements. At the present time, based on 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	3 Months Ended
Rate Matters and Regulation	Mar. 31, 2016
Regulated Operations [Abstract]
Rate Matters and Regulation	Rate Matters and Regulation Regulation and Rates Except as set forth below, the circumstances set forth in Note 15 to the Company's Consolidated Financial Statements included in the Company's 2015 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. Pending Regulatory Matters Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates. FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule. Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities. The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the District of Columbia Court of Appeals challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement. The court has not yet acted on OG&E's appeal. The Company cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. The Company has no reason to believe that the implementation of Order No. 1000 will impact those transmission projects for which OG&E has received a notice to proceed from the SPP. Oklahoma Demand Program Rider Review - SmartHours Program In July 2012, OG&E filed an application with the OCC to recover certain costs associated with Demand Programs through the Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off-peak hours during the months of May through October, by offering lower rates to those customers in the off-peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation. In December 2012, the OCC issued an order approving the recovery of costs associated with the Demand Programs, including the lost revenues associated with the SmartHours program, subject to the Oklahoma PUD staff review. In March 2014, the Oklahoma PUD staff began their review of the Demand Program cost, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the Oklahoma PUD staff on the methodology to be used to calculate lost revenues associated with the SmartHours program and the amount of lost revenue for 2013, which totaled $10.1 million. The agreement also included utilizing the same methodology for calculating lost revenues for 2014 and beyond. In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues (approximately $10.0 million annually), in accordance with the agreement that it believed had been reached with the Oklahoma PUD staff. In April 2015, the Oklahoma PUD staff filed an application, seeking an order from the OCC, for determining the proper methodology for calculating lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues. In the application, the Oklahoma PUD staff recommends the OCC approve the Oklahoma PUD staff methodology for calculating lost revenues associated with the SmartHours program, which differs from the methodology that OG&E believes it agreed upon and which would result in recovery of lost revenue for 2013 of $2.6 million, a reduction of $7.5 million from the amount recorded by OG&E for 2013. OG&E believes the methodology agreed to in November 2014 was consistent with the 2012 OCC order and it is probable that OG&E will recover $10.1 million of lost revenues associated with 2013, $11.6 million associated with 2014 and $14.9 million associated with 2015. Through March 31, 2016, OG&E had collected from its customers approximately $12.6 million of the $36.6 million of lost revenues for 2013, 2014 and 2015. A hearing on the Oklahoma PUD staff’s application was heard by the ALJ on June 30, 2015 and July 1, 2015. On March 28, 2016, the ALJ issued her recommendation in the case. She found, among other things, that OG&E and the Oklahoma PUD staff had not reached an agreement on all aspects of the calculation of lost revenues, that OG&E’s methodology for calculating lost revenues was not consistent with the provisions of OG&E’s tariff, and that the PUD staff’s methodology for calculating lost revenues was proper. The ALJ recommended that the OCC order OG&E to adjust its calculation of SmartHours lost revenue for 2013 through 2015 consistent with the PUD staff’s methodology, but that such adjustment should only be applied on a prospective basis following the issuance of an order by the OCC. The ALJ’s recommendation is not clear on whether the phrase “on a prospective basis” would allow OG&E to recover the remaining $24.0 million of 2013, 2014 and 2015 lost revenues that OG&E recorded pursuant to its methodology, or only the amounts that OG&E has collected at the time of an OCC order. The OCC can accept, modify or reject in whole or in part the ALJ’s recommendation. To the extent the OCC does not authorize OG&E to collect and retain the remaining lost revenue that it has recorded, OG&E will incur an impairment charge. OG&E is unable to predict what actions the OCC will take, or when the OCC will rule in this case. Environmental Compliance Plan On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of its Mustang Modernization Plan which calls for replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 with 400 MWs of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance plan to be approximately $1.1 billion. Approximately seven months after OG&E filed its application, the OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding. On June 8, 2015, the ALJ issued his report on OG&E's application. While the ALJ in his report agreed that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s ECP is the best approach, the ALJ's report included several recommendations. OG&E filed exceptions to the ALJ's report and on July 21, 2015, Commissioner Bob Anthony issued his deliberation statement that was consistent with many parts of the ALJ's report, including the ALJ’s support of OG&E’s ECP, the ALJ’s recommendation to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other cost recovery issues until the next general rate case. 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 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. OG&E did not seek modification to any other provisions of the OCC order, including cost recovery. OG&E also agreed that it would not implement a rider for recovery of the costs of the ECP until and unless authorized by the OCC in a subsequent proceeding. On December 23, 2015, the OCC rejected, by a two to one vote, a proposal by Commissioner Dana Murphy to grant OG&E's December 11, 2015 motion. On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install dry scrubbers at the Sooner facility on or before May 2, 2016. OG&E's application does not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates. At the hearing on OG&E's application to approve OG&E's decision to install dry scrubbers and in testimony filed in support of its application, OG&E stated that it would cancel the dry scrubber project if the OCC did not approve OG&E's application on or before May 2, 2016. On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Other parties to the proceeding have the opportunity to appeal the OCC's decision to the Oklahoma Supreme Court. As of March 31, 2016, OG&E had incurred $107.3 million of construction work in progress on the dry scrubbers. Fuel Adjustment Clause Review for Calendar Year 2014 On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On April 7, 2016, a hearing was held in this matter, at which time the ALJ said she would recommend that the OCC find that for the calendar year 2014 OG&E’s electric generation, purchased power and fuel procurement processes and costs were prudent. The Company expects to receive an order from the OCC by the end of the second quarter 2016. Integrated Resource Plans In August 2015, OG&E initiated the process to update its IRP pursuant to the OCC rules. After engaging interested stakeholders in August and September, OG&E finalized the 2015 IRP and submitted it to the OCC on October 1, 2015. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the action plan contained in the IRP submitted in 2014. Oklahoma Rate Case Filing As previously reported in the Company's 2015 Form 10-K, on December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 million and a 10.25 percent return on equity based on a common equity percentage of 53 percent. The rate case was based on a June 30, 2015 test year, and included recovery of $1.6 billion of electric infrastructure additions since its last general rate case in Oklahoma, the impact of the expiration of OG&E's wholesale contracts, increased operating costs such as vegetation management and increased recovery of depreciation and plant dismantlement of approximately $8.0 million. Each 0.25 percent change in the requested return on equity affects the requested rate increase by approximately $9.0 million. In late March 2016, the PUD Staff and other intervenors filed testimony in the case. The PUD Staff recommended a $6.1 million annual rate increase based on a return on equity of 9.25 percent and a common equity percentage of 53 percent. Included in the PUD Staff recommendation is a reduction of $33.0 million to OG&E’s requested increase for depreciation and plant dismantlement. The staff of the Oklahoma Attorney General made a recommendation to reduce rates $10.8 million based on a return on equity of 9.25 percent and a common equity percentage of 50 percent, as well as a recommendation to reduce rates $13.7 million based on a return on equity of 8.90 percent and a common equity percentage of 53 percent. Included in the Attorney General's recommendation is a reduction of $20.9 million to OG&E’s requested increase for depreciation and plant dismantlement. The Oklahoma Industrial Electric Consumers recommended a $47.9 million annual rate decrease based on a return on equity of 9.00 percent and a common equity percentage of 53 percent. Included in the Oklahoma Industrial Electric Consumers' recommendation is a reduction of $52.5 million to OG&E’s requested increase for depreciation and plant dismantlement. The hearings in this matter began on May 3, 2016. While there is no statutory deadline for the ALJ to make a recommendation or for the commission to issue a final order, OG&E is allowed to implement increased rates subject to refund, 180 days after the filing of its application on December 18, 2015. Arkansas Rate Case Filing OG&E intends to file a general rate case with the APSC by August 15, 2016.

Summary of Significant Accounting Policies (Policies)	3 Months Ended
Summary of Significant Accounting Policies (Policies)	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Consolidation, Policy [Policy Text Block]	Organization The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. The accounts of the Company and its wholly owned subsidiaries are included in the Condensed Consolidated Financial Statements. All intercompany transactions and balances are eliminated in consolidation. The Company generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and lacks the power to direct activities that most significantly impact economic performance. The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business. The natural gas midstream operations segment represents the Company's investment in Enable through its wholly owned subsidiary OGE Holdings. Enable is engaged in the business of gathering, processing, transporting and storing natural gas. Enable's natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns a crude oil gathering business in the Bakken shale formation, principally located in the Williston basin of North Dakota. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. Enable was formed effective May 1, 2013 by the Company, the ArcLight group and CenterPoint to own and operate the midstream businesses of the Company and CenterPoint. In the formation transaction, the Company and the ArcLight group contributed Enogex LLC to Enable and the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable. The Company's contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by CenterPoint and the Company, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading. In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at March 31, 2016 and December 31, 2015, the results of its operations and cash flows for the three months ended March 31, 2016 and 2015, have been included and are of a normal recurring nature except as otherwise disclosed. Due to seasonal fluctuations and other factors, the Company's operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2015 Form 10-K.
Public Utilities, Policy [Policy Text Block]	Accounting Records The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities based on the expected flowback to customers in future rates. Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. Certain prior year amounts have been reclassified to conform with the current year presentation. OG&E records certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refund in future rates. Management continuously monitors the future recoverability of regulatory assets. When in management's judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If OG&E were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets, which could have significant financial effects.
Equity Method Investments, Policy [Policy Text Block]	Investment in Unconsolidated Affiliate The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable 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 adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheets at March 31, 2016. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline. The Company considers distributions received from Enable, which do not exceed cumulative equity in earnings subsequent to the date of investment, to be a return on investment which are classified as operating activities in the Condensed Consolidated Statements of Cash Flows. The Company considers distributions received from Enable in excess of cumulative equity in earnings subsequent to the date of investment to be a return of investment which are classified as investing activities in the Condensed Consolidated Statements of Cash Flows.
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). except for long-term debt which is recorded at the carrying amount. The following table summarizes the fair value and carrying amount of
Income Tax, Policy [Policy Text Block]	The Company files 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. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms. In addition, OG&E and Enable earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.
Earnings Per Share, Policy [Policy Text Block]	Earnings Per Share Basic earnings per share is calculated by dividing net income attributable to the Company by the weighted average number of the Company's common shares outstanding during the period. In the calculation of diluted earnings per share, weighted average shares outstanding are increased for additional shares that would be outstanding if potentially dilutive securities were converted to common stock. Potentially dilutive securities for the Company consist of performance units and restricted stock units.

- Definition

Disclosure of accounting policy for the equity method of accounting for investments in common stock or other interests including unconsolidated subsidiaries, corporate joint ventures, noncontrolling interests in real estate ventures, limited partnerships, and limited liability companies. The accounting policy may include information such as: (1) initially recording an investment in the stock of an investee at cost; (2) adjusting the carrying amount of the investment to recognize the investor's share of the earnings or losses of the investee after the date of acquisition; and (3) adjustments to reflect the investor's share of changes in the investee's capital (dividends). This disclosure may also include a detailed description of the policy for determining the amount of equity method losses recognized after an investment has been reduced to zero as a result of previous losses, reasons for not using the equity method when the investor company owns 20 percent or more of the voting stock of the investee's company (including identification of the significant investee), reasons for using the equity method when the ownership percentage is less than 20 percent, and discussion of recognition of equity method losses when an investor's total investment in an investee includes, in addition to an investment in common stock, other investments such as preferred stock and loans to the investee. An entity also may describe how such investments are assessed for impairment.

+ References + Details

- Definition

Disclosure of accounting policy for income taxes, which may include its accounting policies for recognizing and measuring deferred tax assets and liabilities and related valuation allowances, recognizing investment tax credits, operating loss carryforwards, tax credit carryforwards, and other carryforwards, methodologies for determining its effective income tax rate and the characterization of interest and penalties in the financial statements.

+ References + Details

Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

The following table is a summary of OG&E's regulatory assets and liabilities at:



(In millions)	March 31, 2016		December 31, 2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	37.4	$	36.6
Other (A)	13.4		9.9
Total Current Regulatory Assets	$	50.8	$	46.5
Non-Current
Benefit obligations regulatory asset	$	240.0	$	242.2
Income taxes recoverable from customers, net	56.8		56.7
Smart Grid	43.6		43.6
Deferred storm expenses	30.9		27.6
Unamortized loss on reacquired debt	14.4		14.8
Other	17.1		17.3
Total Non-Current Regulatory Assets	$	402.8	$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	63.2	$	61.3
Other (B)	3.7		7.5
Total Current Regulatory Liabilities	$	66.9	$	68.8
Non-Current
Accrued removal obligations, net	$	255.3	$	254.9
Pension tracker	22.0		17.7
Other (C)	1.0		1.0
Total Non-Current Regulatory Liabilities	$	278.3	$	273.6


(A)	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.


(B)	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.


(C)	Prior year amount of $1.0 million reclassified from deferred other liabilities to Non-Current Regulatory Liabilities.

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following table summarizes changes to the Company's asset retirement obligations during the three months ended March 31, 2016 and 2015.



	Three Months Ended March 31,
(In millions)	2016		2015
Balance at January 1	$	63.3	$	58.6
Accretion expense	0.7		0.6
Liabilities settled	—		(0.3		)
Balance at March 31	$	64.0	$	58.9

Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Net loss		Prior service cost			Total
Balance at December 31, 2015	$	(39.2	)	$	0.1	$	2.5	$	1.5		$	(35.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.8			—		—		(0.4		)	0.4
Balance at March 31, 2016	$	(38.4	)	$	0.1	$	2.5	$	1.1		$	(34.7	)



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1	$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.4			—		0.2			(0.4		)	0.2
Balance at March 31, 2015	$	(36.4	)	$	0.1	$	(7.8	)	$	2.9		$	(41.2	)

Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]



Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended March 31,
(In millions)	2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.2	)	$	(1.2	)	(A)
	(0.4		)	(0.8		)	Tax benefit
	$	(0.8	)	$	(0.4	)	Net of tax

Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.4	)	(A)
Prior service cost	0.6			0.7			(A)
	0.6			0.3			Total before tax
	0.2			0.1			Tax expense
	$	0.4		$	0.2		Net of tax

Total reclassifications for the period	$	(0.4	)	$	(0.2	)	Net of tax


(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Investment in Unconsolidated Affiliate and Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2016

Equity Method Investments and Joint Ventures [Abstract]

The following table summarizes related party transactions between OG&E and Enable during the three months ended March 31, 2016, and 2015.



	Three Months Ended March 31,
(In millions)	2016		2015
Operating Revenues:
Electricity to power electric compression assets	$	2.3	$	3.1
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.8
Natural gas purchases/(sales)	1.5		2.5

Summarized Balance Sheet Financial Information, Equity Method Investment [Table Text Block]

Summarized unaudited financial information for 100 percent of Enable is presented below as of March 31, 2016 and December 31, 2015.



Balance Sheet	March 31,		December 31,
(In millions)	2016		2015
Current assets	$	379	$	381
Non-current assets	10,870		10,857
Current liabilities	279		615
Non-current liabilities	3,123		3,092

Summarized Income Statement Financial Information, Equity Method Investment [Table Text Block]



Income Statement	Three Months Ended March 31,
(In millions)	2016		2015
Operating revenues	$	509	$	616
Cost of NGLs	195		292
Operating income	103		104
Net income	86		91

Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Table Text Block]

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three months ended March 31, 2016 and 2015.



	Three Months Ended March 31,
(In millions)	2016		2015
OGE's share of Enable Net Income	$	21.3	$	23.8
Amortization of basis difference	2.9		3.5
Elimination of Enogex Holdings fair value and other adjustments	4.1		4.4
Equity in earnings of unconsolidated affiliates	$	28.3	$	31.7

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following table summarizes the fair value and carrying amount of the Company's long-term debt at March 31, 2016 and December 31, 2015.



	March 31, 2016				December 31, 2015
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,384.3	$	2,748.1	$	2,493.9	$	2,754.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.0		9.5		10.0		9.2
OGE Energy Senior Notes	99.6		99.9		99.5		99.9

Stock Based Compensation (Tables)

3 Months Ended

Mar. 31, 2016

Stock-Based Compensation [Abstract]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]



	Three Months Ended March 31,
(In millions)	2016		2015
Performance units
Total shareholder return	$	1.1	$	1.9
Earnings per share	0.6		0.5
Total performance units	1.7		2.4
Restricted stock	—		—
Total compensation expense	1.7		2.4
Less: Amount paid by unconsolidated affiliates	—		0.3
Net compensation expense	$	1.7	$	2.1
Income tax benefit	$	0.6	$	0.8

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

The following table summarizes the activity of the Company's stock-based compensation during the three months ended March 31, 2016.



	Units/Shares	Fair Value Per Share
Grants
Performance units (Total shareholder return)	280,604	$	20.84
Performance units (Earnings per share)	93,533	$	26.59

Common Equity (Tables)

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

Basic and diluted earnings per share for the Company were calculated as follows:



	Three Months Ended March 31,
(In millions)	2016		2015
Net Income	$	25.2	$	43.2
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.5
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—		—
Diluted average common shares outstanding	199.7		199.5
Basic Earnings Per Average Common Share	$	0.13	$	0.22
Diluted Earnings Per Average Common Share	$	0.13	$	0.22
Anti-dilutive shares excluded from earnings per share calculation	—		—

Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2016

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]



SERIES			DATE DUE	AMOUNT
				(In millions)
0.05%	-	0.39%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.43%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.40%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Short-Term Debt and Credit Facilities (Tables)

3 Months Ended

Mar. 31, 2016

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The following table provides information regarding the Company's revolving credit agreements and available cash at March 31, 2016.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	187.5	0.74	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0		1.7		0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0	$	189.2	0.95	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2016.


(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)	As of March 31, 2016, commitments of $16.3 million and $8.7 million of the Company's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.

Retirement Plans and Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2016

Retirement Plans and Postretirement Benefit Plans [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

Net Periodic Benefit Cost



	Pension Plan						Restoration of Retirement Income Plan				Postretirement Benefit Plans
	Three Months Ended March 31,						Three Months Ended March 31,				Three Months Ended March 31,
(In millions)	2016			2015			2016		2015		2016			2015
Service cost	$	4.4		$	4.5		$	0.1	$	0.4	$	0.3		$	0.5
Interest cost	6.6			6.4			0.1		0.2		2.3			2.6
Expected return on plan assets	(10.5		)	(11.8		)	—		—		(0.6		)	(0.6		)
Amortization of net loss	4.2			4.3			0.2		0.1		0.5			3.4
Amortization of unrecognized prior service cost (A)	—			0.1			—		—		(2.2		)	(4.1		)
Total net periodic benefit cost	4.7			3.5			0.4		0.7		0.3			1.8
Less: Amount paid by unconsolidated affiliates	1.3			1.1			—		—		0.1			0.3
Net periodic benefit cost (B)	$	3.4		$	2.4		$	0.4	$	0.7	$	0.2		$	1.5


(A)	Unamortized prior service cost is amortized on a straight-line basis over the average remaining service period to the first eligibility age of participants who are expected to receive a benefit and are active at the date of the plan amendment.


(B)	In addition to the $4.0 million and $4.6 million of net periodic benefit cost recognized during the three months ended March 31, 2016 and 2015, respectively, the Company recognized the following:


•	an increase in pension expense in the three months ended March 31, 2016 and 2015 of $2.3 million and $3.0 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and


•	an increase in postretirement medical expense in the three months ended March 31, 2016 and 2015 of $2.0 million and $1.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1).

Schedule of Capitalized Pension and Postretirement Cost [Table Text Block]



	Three Months Ended
	March 31,
(In millions)	2016		2015
Capitalized portion of net periodic pension benefit cost	$	1.2	$	0.8
Capitalized portion of net periodic postretirement benefit cost	0.1		0.5

Report of Business Segments (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following tables summarize the results of the Company's business segments for the three months ended March 31, 2016 and 2015.



Three Months Ended March 31, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	433.1	$	—		$	—		$	—		$	433.1
Cost of sales	177.9		—			—			—			177.9
Other operation and maintenance	116.3		0.2			(2.6		)	—			113.9
Depreciation and amortization	76.7		—			1.8			—			78.5
Taxes other than income	23.6		—			1.3			—			24.9
Operating income (loss)	38.6		(0.2		)	(0.5		)	—			37.9
Equity in earnings of unconsolidated affiliates	—		28.3			—			—			28.3
Other income (expense)	5.3		—			0.3			(0.1		)	5.5
Interest expense	35.5		—			0.9			(0.1		)	36.3
Income tax expense (benefit)	2.3		10.1			(2.2		)	—			10.2
Net income	$	6.1	$	18.0		$	1.1		$	—		$	25.2
Investment in unconsolidated affiliates	$	—	$	1,187.4		$	—		$	—		$	1,187.4
Total assets	$	8,288.5	$	1,467.9		$	98.7		$	(331.8	)	$	9,523.3



Three Months Ended March 31, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	480.1	$	—		$	—		$	—		$	480.1
Cost of sales	211.6		—			—			—			211.6
Other operation and maintenance	114.3		0.8			(3.4		)	—			111.7
Depreciation and amortization	73.8		—			2.1			—			75.9
Taxes other than income	23.1		—			1.4			—			24.5
Operating income (loss)	57.3		(0.8		)	(0.1		)	—			56.4
Equity in earnings of unconsolidated affiliates	—		31.7			—			—			31.7
Other income (expense)	2.9		—			2.5			—			5.4
Interest expense	36.8		—			0.6			—			37.4
Income tax expense (benefit)	6.3		8.1			(1.5		)	—			12.9
Net income	$	17.1	$	22.8		$	3.3		$	—		$	43.2
Investment in unconsolidated affiliates	$	—	$	1,315.7		$	—		$	—		$	1,315.7
Total assets	$	8,217.7	$	1,476.7		$	122.3		$	(332.4	)	$	9,484.3

Summary of Significant Accounting Policies Equity Ownership (Details)	Mar. 31, 2016
CenterPoint [Member]
Percentage Share of Management Rights	50.00%
OGE Holdings [Member]
Percentage Share of Management Rights	50.00%

Summary of Significant Accounting Policies Regulated Operations (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Dec. 31, 2015

Schedule of Regulatory Assets and Liabilities [Line Items]

Fuel clause over recoveries

$ 63.2

$ 61.3

Regulatory Assets, Current

50.8

46.5

Regulatory Assets, Noncurrent

402.8

402.2

Regulatory Liability, Current

66.9

68.8

Regulatory Liability, Noncurrent

278.3

273.6

Prior Period Reclassification Adjustment

1.0

Other Regulatory Liabilities [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Liability, Current

^[1]

3.7

7.5

Regulatory Liability, Noncurrent

^[2]

1.0

Accrued removal obligations [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Liability, Noncurrent

255.3

254.9

Pension tracker [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Liability, Noncurrent

22.0

17.7

Oklahoma demand program rider under recovery [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Current

^[3]

37.4

36.6

Other Regulatory Assets [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Current

^[3]

13.4

9.9

Regulatory Assets, Noncurrent

17.1

17.3

Benefit obligations regulatory asset [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Noncurrent

240.0

242.2

Income taxes recoverable from customers, net [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Noncurrent

56.8

56.7

Smart Grid [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Noncurrent

43.6

Deferred storm expenses [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Noncurrent

30.9

27.6

Unamortized loss on reacquired debt [Member]

Schedule of Regulatory Assets and Liabilities [Line Items]

Regulatory Assets, Noncurrent

$ 14.4

$ 14.8

[1]	Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
[2]	Prior year amount of $1.0 million reclassified from deferred other liabilities to Non-Current Regulatory Liabilities.
[3]	Included in Other Current Assets on the Condensed Consolidated Balance Sheets.

Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 63.3	$ 58.6
Accretion expense	0.7	0.6
Liabilities settled	0.0	(0.3)
Balance at March 31	$ 64.0	$ 58.9

Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Accumulated other comprehensive income (loss)

$ (34.7)

$ (41.2)

$ (35.1)

$ (41.4)

Amounts reclassified from accumulated other comprehensive income (loss)

0.4

0.2

Amounts Reclassified from Accumulated OCI, Net of Tax and Noncontrolling Interest

0.4

0.2

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)

0.8

0.4

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

^[1]

(1.2)

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax

(0.4)

(0.8)

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amounts reclassified from accumulated other comprehensive income (loss)

(0.4)

0.2

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

^[1]

0.0

(0.4)

Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax

^[1]

0.6

0.7

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax

0.6

0.3

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax

0.2

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)

(38.4)

(36.4)

(39.2)

(36.8)

Amounts reclassified from accumulated other comprehensive income (loss)

0.8

0.4

Defined Benefit Plans Income Loss [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Accumulated other comprehensive income (loss)

2.5

(7.8)

2.5

(8.0)

Amounts reclassified from accumulated other comprehensive income (loss)

0.0

0.2

Defined Benefit Plan Prior Service Cost [Member] | Pension Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Accumulated other comprehensive income (loss)

0.1

Amounts reclassified from accumulated other comprehensive income (loss)

0.0

Defined Benefit Plan Prior Service Cost [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Accumulated other comprehensive income (loss)

1.1

2.9

$ 1.5

$ 3.3

Amounts reclassified from accumulated other comprehensive income (loss)

$ (0.4)

[1]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 10 for additional information).

Summary of Significant Accounting Policies Summary of Significant Accounting Policies Reclassifications (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Prior Period Reclassification Adjustment	$ 1.0
Adjustments for New Accounting Pronouncement [Member]
Prior Period Reclassification Adjustment	$ 16.8

Investment in Unconsolidated Affiliate and Related Party Transactions (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Apr. 30, 2014	Mar. 31, 2016	Mar. 31, 2015	May 13, 2014	May 01, 2013
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 775.5
Enable Midstream Partners [Member]
Schedule of Equity Method Investments [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	25,000,000
Distributions received		$ 35.3	$ 34.3
Enogex LLC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Enogex LLC Contributed					100.00%
Increase in fair value of net assets					$ 2,200.0
Southeast Supply Header, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of Subsidiary Contributed				24.95%
OGE Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Limited Partner Units Owned		111,000,000
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		26.30%
Subordinated Units Held by Limited Partners of the LLC or LP		68,200,000
Percent of Incentive Distribution Rights		60.00%
CenterPoint [Member]
Schedule of Equity Method Investments [Line Items]
Percent of Incentive Distribution Rights		40.00%

Investment in Unconsolidated Affiliate and Related Party Transactions Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 2.9		$ 1.7
Og and E [Member] \| Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	2.3	$ 3.1
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	1.3	2.8
Natural Gas Transportation [Member] \| Og and E [Member] \| Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	8.8	8.8
Natural Gas Purchases [Member] \| Og and E [Member] \| Enable Midstream Partners [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	1.5	2.5
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	$ 7.1	$ 10.0

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Summarized Financial Information of Equity Method Investment [Line Items]
Current assets	$ 379.0	$ 381.0
Non-current assets	10,870.0	10,857.0
Current liabilities	279.0	615.0
Non-current liabilities	$ 3,123.0	$ 3,092.0

- Definition

The amount of current liabilities reported by an equity method investment of the entity.

+ References + Details

- Definition

The amount of noncurrent assets reported by an equity method investment of the entity.

+ References + Details

- Definition

The amount of noncurrent liabilities reported by an equity method investment of the entity.

+ References + Details

Investment in Unconsolidated Affiliate and Related Party Transactions Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Operating revenues	$ 509.0	$ 616.0
Cost of NGLs	195.0	292.0
Operating income	103.0	104.0
Net income	$ 86.0	$ 91.0

- Definition

The amount of net income (loss) reported by an equity method investment of the entity.

+ References + Details

Investment in Unconsolidated Affiliate and Related Party Transactions Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Schedule of Equity Method Investments [Line Items]
OGE's share of Enable Net Income	$ 21.3	$ 23.8
Amortization of basis difference	2.9	3.5
Elimination of Enogex Holdings fair value and other adjustments	4.1	4.4
Equity in earnings of unconsolidated affiliates	28.3	31.7
Natural Gas Midstream Operations [Member]
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated affiliates	$ 28.3	$ 31.7

Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	$ 2,384.3	$ 2,493.9
Long-Term Debt, Fair Value	2,748.1	2,754.6
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	135.4	135.4
Long-Term Debt, Fair Value	135.4	135.4
OG&E Tinker Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	10.0	10.0
Long-Term Debt, Fair Value	9.5	9.2
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	99.6	99.5
Long-Term Debt, Fair Value	99.9	99.9
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0.0	$ 0.0

Stock Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Tax Benefit from Compensation Expense	$ 0.6	$ 0.8
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, Equity Instruments Other than Options, Grants in Period	93,533
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 26.59
Total Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	280,604
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 20.84
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	$ 1.7	2.4
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	0.0	0.0
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	1.7	2.4
Amount paid by unconsolidated affiliates	0.0	0.3
Compensation Expense, Net of Unconsolidated Affiliates	1.7	2.1
Performance Units Related to Earnings Per Share [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	0.6	0.5
Total Shareholder Return [Member] \| Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation Expense	$ 1.1	$ 1.9
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	0
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Paid for Tax Withholding	901

Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - Automatic Dividend Reinvestment and Stock Purchase Plan [Member]	3 Months Ended
	Mar. 31, 2016 shares
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 Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Net income	$ 25.2	$ 43.2
Basic Average Common Shares Outstanding	199.7	199.5
Contingently Issuable Shares (Performance and Restricted Stock Units)	0.0	0.0
Diluted Average Common Shares Outstanding	199.7	199.5
Earnings Per Share, Basic and Diluted [Abstract]
Basic earnings per average common share attributable to OGE Energy common shareholders	$ 0.13	$ 0.22
Diluted earnings per average common share attributable to OGE Energy common shareholders	$ 0.13	$ 0.22
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0.0	0.0
Retained Earnings
Net income	$ 25.2	$ 43.2

- Definition

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References + Details

Long-Term Debt (Details) $ in Millions	3 Months Ended
Long-Term Debt (Details) $ in Millions	Mar. 31, 2016 USD ($)
Debt Instrument [Line Items]
Percent of Principal Amount Subject to Optional Tender	100.00%
Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 01, 2027
Redeemable during the next 12 months
Debt Instrument [Line Items]
Total long-term debt	$ 135.4
Redeemable during the next 12 months \| Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Series Minimum	0.05%
Series Maximum	0.39%
Redeemable during the next 12 months \| Muskogee Industrial Authority, Janaury 1, 2025 [Member]
Debt Instrument [Line Items]
Series Minimum	0.07%
Series Maximum	0.43%
Redeemable during the next 12 months \| Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Series Minimum	0.05%
Series Maximum	0.40%
OG&E [Member] \| Redeemable during the next 12 months \| Garfield Industrial Authority, January 1, 2025 [Member]
Debt Instrument [Line Items]
Long term debt, gross	$ 47.0
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
OG&E [Member] \| Redeemable during the next 12 months \| Muskogee Industrial Authority, June 1, 2027 [Member]
Debt Instrument [Line Items]
Long term debt, gross	$ 56.0

Short-Term Debt and Credit Facilities (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Dec. 31, 2015

Line of Credit Facility [Line Items]

Short-term debt

$ 187.5

$ 0.0

Line of Credit Facility [Abstract]

Aggregate Commitment

1,150.0

Amount Outstanding

^[1]

$ 189.2

Weighted Average Interest Rate

0.95%

OGE Energy [Member]

Line of Credit Facility [Abstract]

Weighted Average Interest Rate

0.74%

OGE Energy [Member]

Line of Credit Facility [Abstract]

Aggregate Commitment

^[2]

$ 750.0

Amount Outstanding

^[1],[2]

$ 187.5

Weighted Average Interest Rate

^[2],[3]

0.74%

Maturity

^[2],[4]

Dec. 13, 2018

OG&E [Member]

Line of Credit Facility [Abstract]

Aggregate Commitment

^[5]

$ 400.0

Letters of Credit Outstanding, Amount

^[1],[5]

$ 1.7

Weighted Average Interest Rate

^[3],[5]

0.95%

Maturity

^[4],[5]

Dec. 13, 2018

Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt

2 years

Short Term Borrowing Capacity That Has Regulatory Approval

$ 800.0

December 13, 2017 [Member] | OGE Energy [Member]

Line of Credit Facility [Abstract]

Aggregate Commitment

16.3

December 13, 2017 [Member] | OG&E [Member]

Line of Credit Facility [Abstract]

Aggregate Commitment

$ 8.7

[1]	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2016.
[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]	As of March 31, 2016, commitments of $16.3 million and $8.7 million of the Company's and OG&E's credit facilities, respectively, were not extended and unless the non-extending lender is replaced in accordance with the terms of the credit facility, such commitments will expire December 13, 2017.
[5]	This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

Retirement Plans and Postretirement Benefit Plans (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Net periodic benefit cost

$ 4.0

$ 4.6

Pension Plans, Defined Benefit [Member]

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Service cost

4.4

4.5

Interest cost

6.6

6.4

Expected return on plan assets

(10.5)

(11.8)

Amortization of net loss

4.2

4.3

Amortization of unrecognized prior service cost

^[1]

0.0

0.1

Net periodic benefit cost

4.7

3.5

Amount Attributable to Unconsolidated Affiliates

1.3

1.1

Net Periodic Benefit Cost, Net of Unconsolidated Affiliates

^[2]

3.4

2.4

Capitalized Portion of Net Periodic Benefit Cost

1.2

0.8

Pension Plans, Defined Benefit [Member] | OKLAHOMA

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Additional Pension Expense to Meet State Requirements

2.3

3.0

Restoration of Retirement Income Plan [Member]

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Service cost

0.1

0.4

Interest cost

0.1

0.2

Expected return on plan assets

0.0

Amortization of net loss

0.2

0.1

Amortization of unrecognized prior service cost

^[1]

0.0

Net periodic benefit cost

0.4

0.7

Amount Attributable to Unconsolidated Affiliates

0.0

Net Periodic Benefit Cost, Net of Unconsolidated Affiliates

^[2]

0.4

0.7

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Service cost

0.3

0.5

Interest cost

2.3

2.6

Expected return on plan assets

(0.6)

Amortization of net loss

0.5

3.4

Amortization of unrecognized prior service cost

^[1]

(2.2)

(4.1)

Net periodic benefit cost

0.3

1.8

Amount Attributable to Unconsolidated Affiliates

0.1

0.3

Net Periodic Benefit Cost, Net of Unconsolidated Affiliates

^[2]

0.2

1.5

Capitalized Portion of Net Periodic Benefit Cost

0.1

0.5

Other Postretirement Benefit Plans, Defined Benefit [Member] | OKLAHOMA

Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]

Additional Postretirement Medical Expense to Meet State Requirements

$ 2.0

$ 1.4

[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 $4.0 million and $4.6 million of net periodic benefit cost recognized during the three months ended March 31, 2016 and 2015, respectively, the Company recognized the following: •an increase in pension expense in the three months ended March 31, 2016 and 2015 of $2.3 million and $3.0 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1); and •an increase in postretirement medical expense in the three months ended March 31, 2016 and 2015 of $2.0 million and $1.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction, which are included in the Pension tracker regulatory liability (see Note 1).

Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 433.1	$ 480.1
Cost of sales	177.9	211.6
Other operation and maintenance	113.9	111.7
Depreciation and amortization	78.5	75.9
Taxes other than income	24.9	24.5
OPERATING INCOME	37.9	56.4
Equity in earnings of unconsolidated affiliates	28.3	31.7
Other income (expense)	5.5	5.4
Interest expense	36.3	37.4
Income tax expense (benefit)	10.2	12.9
NET INCOME	25.2	43.2
Investment in unconsolidated affiliates	1,187.4	1,315.7	$ 1,194.4
Total assets	9,523.3	9,484.3	$ 9,580.6
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	433.1	480.1
Cost of sales	177.9	211.6
Other operation and maintenance	116.3	114.3
Depreciation and amortization	76.7	73.8
Taxes other than income	23.6	23.1
OPERATING INCOME	38.6	57.3
Equity in earnings of unconsolidated affiliates	0.0	0.0
Other income (expense)	5.3	2.9
Interest expense	35.5	36.8
Income tax expense (benefit)	2.3	6.3
NET INCOME	6.1	17.1
Investment in unconsolidated affiliates	0.0	0.0
Total assets	8,288.5	8,217.7
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0
Cost of sales	0.0	0.0
Other operation and maintenance	0.2	0.8
Depreciation and amortization	0.0	0.0
Taxes other than income	0.0	0.0
OPERATING INCOME	(0.2)	(0.8)
Equity in earnings of unconsolidated affiliates	28.3	31.7
Other income (expense)	0.0	0.0
Interest expense	0.0	0.0
Income tax expense (benefit)	10.1	8.1
NET INCOME	18.0	22.8
Investment in unconsolidated affiliates	1,187.4	1,315.7
Total assets	1,467.9	1,476.7
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0
Cost of sales	0.0	0.0
Other operation and maintenance	(2.6)	(3.4)
Depreciation and amortization	1.8	2.1
Taxes other than income	1.3	1.4
OPERATING INCOME	(0.5)	(0.1)
Equity in earnings of unconsolidated affiliates	0.0	0.0
Other income (expense)	0.3	2.5
Interest expense	0.9	0.6
Income tax expense (benefit)	(2.2)	(1.5)
NET INCOME	1.1	3.3
Investment in unconsolidated affiliates	0.0	0.0
Total assets	98.7	122.3
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0
Cost of sales	0.0	0.0
Other operation and maintenance	0.0	0.0
Depreciation and amortization	0.0	0.0
Taxes other than income	0.0	0.0
OPERATING INCOME	0.0	0.0
Equity in earnings of unconsolidated affiliates	0.0	0.0
Other income (expense)	(0.1)	0.0
Interest expense	(0.1)	0.0
Income tax expense (benefit)	0.0	0.0
NET INCOME	0.0	0.0
Investment in unconsolidated affiliates	0.0	0.0
Total assets	$ (331.8)	$ (332.4)

Rate Matters and Regulation (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Annual Recovery of Lost Revenues Through Rate Implementation	$ 10.0
Additional Plant Dismantlement Costs	$ 8.0
Change in Requested Return on Equity	0.25%
Change in Requested Rate Increase	$ 9.0
Oklahoma Attorney General's Staff [Member]
Reduction to Requested Additional Plant Dismantlement Costs	20.9
Oklahoma Public Utility Division Staff [Member]
Recommended Rate Increase	$ 6.1
Recommended Return on Equity	9.25%
Recommended Common Equity Percentage	53.00%
Reduction to Requested Additional Plant Dismantlement Costs	$ 33.0
Oklahoma Industrial Electric Consumers [Member]
Recommended Return on Equity	9.00%
Recommended Common Equity Percentage	53.00%
Reduction to Requested Additional Plant Dismantlement Costs	$ 52.5
Recommended Rate Decrease	47.9
Regional Haze [Member]
Estimated Environmental Capital Costs		$ 1,100.0
SmartHours Program [Member]
Lost Revenue Associated with Customer Programs	36.6	14.9	$ 11.6	$ 10.1
Remaining Lost Revenues to be Recovered Through Rates	24.0
Regulated Operating Revenue, Other	12.6
Oklahoma Public Utility Division Staff [Member] \| SmartHours Program [Member]
Lost Revenue Associated with Customer Programs				2.6
Reduction of Revenue				$ 7.5
Environmental Compliance Plan [Member]
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	107.3
OKLAHOMA
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 92.5
Public Utilities, Requested Return on Equity, Percentage	10.25%
Public Utilities, Requested Equity Capital Structure, Percentage	53.00%
Investments Since Last Rate Case		$ 1,600.0
Recommendation 1 [Member] \| Oklahoma Attorney General's Staff [Member]
Recommended Return on Equity	9.25%
Recommended Common Equity Percentage	50.00%
Recommended Rate Decrease	$ 10.8
Recommendation 2 [Member] \| Oklahoma Attorney General's Staff [Member]
Recommended Return on Equity	8.90%
Recommended Common Equity Percentage	53.00%
Recommended Rate Decrease	$ 13.7