10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period endedJune 30, 2016

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1481638
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

405-553-3000

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.þ  Yes  o  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).þ  Yes  o  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer  þ	Accelerated filer  o
Non-accelerated filer    o (Do not check if a smaller reporting company)	Smaller reporting company  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).o  Yes   þ  No

At June 30, 2016, there were 199,702,025 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDEDJUNE 30, 2016

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS	ii
FORWARD-LOOKING STATEMENTS	1
Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	2
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4
Condensed Consolidated Balance Sheets	5
Condensed Consolidated Statements of Changes in Stockholders' Equity	7
Notes to Condensed Consolidated Financial Statements	8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures About Market Risk	46
Item 4. Controls and Procedures	46
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	48
Item 1A. Risk Factors	48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6. Exhibits	51
Signature	52

i

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations that are found throughout this Form 10-Q.

Abbreviation	Definition
2015 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2015
ALJ	Administrative Law Judge
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ASU	Financial Accounting Standards Board Accounting Standards Update
AVEC	Arkansas Valley Electric Cooperative Corporation
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2	Carbon dioxide
Company	OGE Energy, collectively with its subsidiaries
CSAPR	Cross-State Air Pollution Rule
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
ECP	Environmental Compliance Plan
Enable	Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC	Enogex LLC, collectively with its subsidiaries (effective July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
Federal Clean Water Act	Federal Water Pollution Control Act of 1972, as amended
FERC	Federal Energy Regulatory Commission
FIP	Federal implementation plan
GAAP	Accounting principles generally accepted in the United States
IRP	Integrated Resource Plans
kV	Kilovolt
MATS	Mercury and Air Toxics Standards
Mustang Modernization Plan	OG&E's plan to replace the 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
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
ODEQ	Oklahoma Department of Environmental Quality
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 26.3 percent owner of Enable Midstream Partners
Pension Plan	Qualified defined benefit retirement plan
Ppb	Parts per billion
PUD	Public Utility Division of the Oklahoma Corporation Commission
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SESH	Southeast Supply Header, LLC
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

ii

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," areforward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words "anticipate", "believe", "estimate", "expect", "intend", "objective", "plan", "possible", "potential", "project" and similar expressions.  Actual results may vary materiallyfrom those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" in the Company's 2015Form 10-K and"Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factorsthat could cause actual results to differ materiallyfrom the forward-looking statementsinclude, but are not limited to:

• general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;

• the ability ofthe Company and its subsidiariesto access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;

• prices and availability of electricity, coal, natural gasand NGLs;

• the timing and extent of changes in commodity prices, particularly natural gas and NGLs, the competitive effects of the available pipeline capacity in the regionsEnableserves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity onEnable's interstate pipelines;

• the timing and extent of changes in the supply of natural gas, particularly supplies available for gathering byEnable's gathering and processing business and transporting byEnable's interstate pipelines, including the impact of natural gas and NGLs prices on the level of drilling and production activities in the regionsEnableserves;

• business conditions in the energy and natural gas midstream industries, including the demand for natural gas, NGLs, crude oil and midstream services;

• competitive factors including the extent and timing of the entry of additional competition in the markets served bythe Company;

• unusual weather;

• availability and prices of raw materials for current and future construction projects;

• the effect of retroactive repricing of transactions in the SPP markets or adjustments in market pricing mechanisms by the SPP;

• Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition entersthe Company'smarkets;

• environmental laws and regulations that may impactthe Company'soperations;

• changes in accounting standards, rules or guidelines;

• the discontinuance of accounting principles for certain types of rate-regulated activities;

• the cost of protecting assets against, or damage due to, terrorism or cyber-attacks and other catastrophic events;

• advances in technology;

• creditworthiness of suppliers, customers and other contractual parties;

• difficulty in making accurate assumptions and projections regarding future revenues and costs associated with the Company's equity investment inEnable that the Company does not control;and

• other risk factors listed in the reports filed bythe Companywith the Securities and Exchange Commission including those listed in"Item 1A.Risk Factors" andinExhibit 99.01 tothe Company's2015Form 10-K.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions except per share data)	2016			2015			2016			2015
OPERATING REVENUES	$	551.4		$	549.9		$	984.5		$	1,030.0
COST OF SALES	197.7			210.9			375.6			422.5
OPERATING EXPENSES
Other operation and maintenance	127.6			113.2			241.5			224.9
Depreciation and amortization	80.1			76.2			158.6			152.1
Taxes other than income	20.1			22.4			45.0			46.9
Total operating expenses	227.8			211.8			445.1			423.9
OPERATING INCOME	125.9			127.2			163.8			183.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	16.7			28.2			45.0			59.9
Allowance for equity funds used during construction	3.7			1.7			5.3			3.2
Other income	7.6			5.6			13.2			10.5
Other expense	(5.8		)	(2.2		)	(7.5		)	(3.2		)
Net other income	22.2			33.3			56.0			70.4
INTEREST EXPENSE
Interest on long-term debt	35.7			37.0			71.5			73.9
Allowance for borrowed funds used during construction	(1.8		)	(0.8		)	(2.7		)	(1.6		)
Interest on short-term debt and other interest charges	2.1			1.8			3.5			3.1
Interest expense	36.0			38.0			72.3			75.4
INCOME BEFORE TAXES	112.1			122.5			147.5			178.6
INCOME TAX EXPENSE	40.6			35.0			50.8			47.9
NET INCOME	$	71.5		$	87.5		$	96.7		$	130.7
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7			199.6			199.7			199.6
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.8			199.6			199.8			199.6
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.35		$	0.44		$	0.48		$	0.66
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.35		$	0.44		$	0.48		$	0.66
DIVIDENDS DECLARED PER COMMON SHARE	$	0.27500		$	0.25000		$	0.55000		$	0.50000

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

2

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Net income	$	71.5		$	87.5		$	96.7		$	130.7
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4, $0.6, $0.8 and $1.4, respectively	0.7			0.8			1.5			1.2
Settlement cost, net of tax of $3.2, $0, $3.2 and $0, respectively	5.0			—			5.0			—
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0, $0.2, $0 and $0.4, respectively	—			0.4			—			0.6
Amortization of prior service cost, net of tax of ($0.3), ($0.2), ($0.5) and ($0.5), respectively	(0.4		)	(0.5		)	(0.8		)	(0.9		)
Other comprehensive income, net of tax	5.3			0.7			5.7			0.9
Comprehensive income	$	76.8		$	88.2		$	102.4		$	131.6

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	96.7		$	130.7
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	158.6			152.1
Deferred income taxes and investment tax credits	52.2			48.1
Equity in earnings of unconsolidated affiliates	(45.0		)	(59.9		)
Distributions from unconsolidated affiliates	45.4			68.9
Allowance for equity funds used during construction	(5.3		)	(3.2		)
Stock-based compensation	3.2			2.4
Regulatory assets	(4.0		)	2.5
Regulatory liabilities	(8.4		)	(2.0		)
Other assets	6.8			4.5
Other liabilities	5.7			(2.4		)
Change in certain current assets and liabilities
Accounts receivable, net	10.0			2.9
Accounts receivable - unconsolidated affiliates	3.1			3.2
Accrued unbilled revenues	(37.4		)	(30.8		)
Fuel, materials and supplies inventories	11.2			(29.7		)
Fuel clause under recoveries	—			64.6
Other current assets	(17.7		)	(10.2		)
Accounts payable	(56.8		)	(40.7		)
Fuel clause over recoveries	(20.0		)	1.6
Other current liabilities	(32.3		)	3.2
Net Cash Provided from Operating Activities	166.0			305.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(331.1		)	(227.7		)
Return of capital - equity method investments	25.2			—
Proceeds from sale of assets	0.2			2.0
Net Cash Used in Investing Activities	(305.7		)	(225.7		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(109.8		)	(99.8		)
Issuance of common stock	—			6.8
Payment of long-term debt	(110.1		)	(0.1		)
Increase in short-term debt	284.4			7.5
Net Cash Provided from (Used in) Financing Activities	64.5			(85.6		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(75.2		)	(5.5		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2			5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,		December 31,
(In millions)	2016		2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	75.2
Accounts receivable, less reserve of $1.5 and $1.4, respectively	163.1		173.1
Accounts receivable - unconsolidated affiliates	—		1.7
Accrued unbilled revenues	90.9		53.5
Income taxes receivable	14.6		17.2
Fuel inventories	107.1		113.8
Materials and supplies, at average cost	75.6		80.1
Other	75.9		55.6
Total current assets	527.2		570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,168.8		1,194.4
Other	72.4		70.7
Total other property and investments	1,241.2		1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,522.7		10,318.3
Construction work in progress	319.4		278.5
Total property, plant and equipment	10,842.1		10,596.8
Less accumulated depreciation	3,372.2		3,274.4
Net property, plant and equipment	7,469.9		7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	401.9		402.2
Other	19.0		20.7
Total deferred charges and other assets	420.9		422.9
TOTAL ASSETS	$	9,659.2	$	9,580.6

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

5

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

	June 30,			December 31,
(In millions)	2016			2015
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	284.4		$	—
Accounts payable - unconsolidated affiliates	1.4			—
Accounts payable	159.7			262.5
Dividends payable	54.9			54.9
Customer deposits	77.5			77.0
Accrued taxes	39.4			45.9
Accrued interest	40.3			42.9
Accrued compensation	35.7			54.4
Long-term debt due within one year	—			110.0
Fuel clause over recoveries	41.3			61.3
Other	38.9			43.9
Total current liabilities	773.5			752.8
LONG-TERM DEBT	2,629.7			2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	300.1			299.9
Deferred income taxes	2,232.6			2,178.2
Regulatory liabilities	283.9			273.6
Other	117.6			121.3
Total deferred credits and other liabilities	2,934.2			2,873.0
Total liabilities	6,337.4			6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,104.5			1,101.3
Retained earnings	2,246.7			2,259.8
Accumulated other comprehensive loss, net of tax	(29.4		)	(35.1		)
Total stockholders' equity	3,321.8			3,326.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,659.2		$	9,580.6

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

6

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)

(In millions)	Common Stock		Premium on Common Stock		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2015	$	2.0	$	1,099.3	$	2,259.8		$	(35.1	)	$	3,326.0
Net income	—		—		96.7			—			96.7
Other comprehensive income, net of tax	—		—		—			5.7			5.7
Dividends declared on common stock	—		—		(109.8		)	—			(109.8		)
Stock-based compensation	—		3.2		—			—			3.2
Balance at June 30, 2016	$	2.0	$	1,102.5	$	2,246.7		$	(29.4	)	$	3,321.8
Balance at December 31, 2014	$	2.0	$	1,085.6	$	2,198.2		$	(41.4	)	$	3,244.4
Net income	—		—		130.7			—			130.7
Other comprehensive income, net of tax	—		—		—			0.9			0.9
Dividends declared on common stock	—		—		(99.8		)	—			(99.8		)
Issuance of common stock	—		6.8		—			—			6.8
Stock-based compensation	—		3.0		—			—			3.0
Balance at June 30, 2015	$	2.0	$	1,095.4	$	2,229.1		$	(40.5	)	$	3,286.0

The accompanying Notes to CondensedConsolidatedFinancial Statements are an integral part hereof.

7

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

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

Enable was formed effective May 1, 2013by 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 andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable.The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by 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 atJune 30, 2016andDecember 31, 2015, the results of its operations for the three and six months endedJune 30, 2016and2015 and its cash flows for thesix months endedJune 30, 2016and2015, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company'soperating results for thethree and six months endedJune 30, 2016are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2016or 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 2015Form 10-K.

8

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates.  Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates.  Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

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

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

	June 30,		December 31,
(In millions)	2016		2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	43.9	$	36.6
SPP cost tracker rider under recovery (A)	7.5		4.5
Other (A)	11.8		5.4
Total Current Regulatory Assets	$	63.2	$	46.5
Non-Current
Benefit obligations regulatory asset	$	237.3	$	242.2
Income taxes recoverable from customers, net	58.3		56.7
Smart Grid	43.5		43.6
Deferred storm expenses	31.8		27.6
Unamortized loss on reacquired debt	14.1		14.8
Other	16.9		17.3
Total Non-Current Regulatory Assets	$	401.9	$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	41.3	$	61.3
Other (B)	4.5		7.5
Total Current Regulatory Liabilities	$	45.8	$	68.8
Non-Current
Accrued removal obligations, net	$	256.2	$	254.9
Pension tracker	26.7		17.7
Other (C)	1.0		1.0
Total Non-Current Regulatory Liabilities	$	283.9	$	273.6

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

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

(C) Prior year amount of$1.0 millionreclassified 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.

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.

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The Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2016. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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

Asset Retirement Obligations

The following table summarizes changes to the Company's asset retirement obligations during thesix months endedJune 30, 2016and2015.

	Six Months Ended June 30,
(In millions)	2016		2015
Balance at January 1	$	63.3	$	58.6
Accretion expense	1.4		1.3
Liabilities settled	—		(0.5		)
Balance at June 30	$	64.7	$	59.4

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months endedJune 30, 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 income		Prior service cost			Total
Balance at December 31, 2015	$	(39.2	)	$	0.1	$	2.5	$	1.5		$	(35.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.5			—		—		(0.8		)	0.7
Settlement cost	5.0			—		—		—			5.0
Net current period other comprehensive income (loss)	6.5			—		—		(0.8		)	5.7
Balance at June 30, 2016	$	(32.7	)	$	0.1	$	2.5	$	0.7		$	(29.4	)

	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)	1.2			—		0.6			(0.9		)	0.9
Balance at June 30, 2015	$	(35.6	)	$	0.1	$	(7.4	)	$	2.4		$	(40.5	)

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The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and six months endedJune 30, 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						Six Months Ended
	June 30,						June 30,
(In millions)	2016			2015			2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.1	)	$	(1.4	)	$	(2.3	)	$	(2.6	)	(A)
Settlement	(8.2		)	—			(8.2		)	—			(A)
	(9.3		)	(1.4		)	(10.5		)	(2.6		)	Total before tax
	(3.6		)	(0.6		)	(4.0		)	(1.4		)	Tax benefit
	$	(5.7	)	$	(0.8	)	$	(6.5	)	$	(1.2	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.6	)	$	—		$	(1.0	)	(A)
Prior service credit	0.7			0.7			1.3			1.4			(A)
	0.7			0.1			1.3			0.4			Total before tax
	0.3			—			0.5			0.1			Tax expense
	$	0.4		$	0.1		$	0.8		$	0.3		Net of tax
Total reclassifications for the period	$	(5.3	)	$	(0.7	)	$	(5.7	)	$	(0.9	)	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

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

TheDecember 31, 2015Balance Sheethas been adjusted for the reclassification of$16.8 millionof debt issuance costs from total deferred charges and other assets to long-term debt to be consistent with the2016presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," in2016.

2. 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

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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 ASU 2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted.ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. 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.

Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments.” The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements.

3. 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.

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Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed100 percentof the equity interests inEnogex LLCto 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 June 30, 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 $34.6 million during the three months endedJune 30, 2016 and 2015, respectively, and $70.6 million and $68.9 million for the six months endedJune 30, 2016 and 2015, respectively. On August 3, 2016, Enable announced a quarterly dividend distribution of$0.3180per unit on its outstanding common and subordinated units, representing the same dividend distribution as the previous quarter.

CenterPoint had previously announced that it was evaluating strategic alternatives for its investment in Enable.  On July 18, 2016, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided notice to the Company of CenterPoint’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner.  Under the terms of the right of first offer, the Company has 30 days from receipt of the notice from CenterPoint to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint Energy Resources Corp. common units and subordinated units.  If the Company were to make an offer under the right of first offer, then CenterPoint would have 30 days to accept such offer.  The Company is currently evaluating its options with respect to the right of first offer.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below.

On May 1, 2013, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2016. Under these agreements, the Company charged operating costs to Enable of $1.3 million and $2.5 million for the three months endedJune 30, 2016 and 2015, respectively, and $2.6 million and $5.3 million for the six months endedJune 30, 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/or Enable are assigned as such.  Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

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 of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $7.0 million and $8.1 million during the three months endedJune 30, 2016 and June 30, 2015, respectively, and $14.1 million and $18.1 million during the six months endedJune 30, 2016 and June 30, 2015, respectively, under the Transitional Seconding Agreement for employment costs.

The Company had accounts receivable from Enable of $2.8 million and $3.4 million as of June 30, 2016 and December 31, 2015, respectively, for amounts billed for transitional services, including the cost of seconded employees. Fuel purchases from Enable are excluded.

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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 thethree and six months endedJune 30, 2016 and 2015.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Operating Revenues:
Electricity to power electric compression assets	$	3.0	$	3.6	$	5.3	$	6.7
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.7	$	17.5	$	17.5
Natural gas purchases/(sales)	5.4		2.1		6.9		4.6

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2016 and December 31, 2015 and for the three and six months endedJune 30, 2016 and 2015.

	June 30,		December 31,
Balance Sheet	2016		2015
(In millions)
Current assets	$	349	$	381
Non-current assets	10,851		10,845
Current liabilities	301		615
Non-current liabilities	3,150		3,080

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Income Statement	2016		2015		2016		2015
(In millions)
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of natural gas and natural gas liquids	254		277		449		569
Operating income	57		93		160		197
Net income	35		77		121		168

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

The Company recorded equity in earnings of unconsolidated affiliates of $16.7 million and $45.0 million for the three and six months endedJune 30, 2016, respectively, and $28.2 million and $59.9 million for the three and six months endedJune 30, 2015, respectively. Equity in earnings of unconsolidated affiliates includes the Company'sshare of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in net assets

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of Enable. The basis difference is the result of the initial contribution of Enogex 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 percentinterest in SESH. 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$768.7 million as of June 30, 2016.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for thethree and six months endedJune 30, 2016 and 2015.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2016		2015		2016		2015
(In millions)
OGE's share of Enable net income	$	9.1	$	20.6	$	30.4	$	44.4
Amortization of basis difference	3.0		3.6		5.9		7.1
Elimination of Enogex Holdings fair value and other adjustments	4.6		4.0		8.7		8.4
Equity in earnings of unconsolidated affiliates	$	16.7	$	28.2	$	45.0	$	59.9

4. 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 nofinancial instruments measured at fair value on a recurring basis atJune 30, 2016 and December 31, 2015, except for long-term debt, which is recorded at the carrying amount.

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The following table summarizes the fair value and carrying amount of the Company's financial instruments at June 30, 2016 and December 31, 2015.

	June 30,				December 31,
	2016				2015
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
Senior Notes	$	2,384.7	$	2,812.5	$	2,493.9	$	2,754.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.9		10.3		10.0		9.2
OGE Energy Senior Notes	99.7		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 which fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

5. Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree and six months endedJune 30, 2016 and 2015related to the Company's performance units and restricted stock.

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015
Performance units
Total shareholder return	$	1.1	$	1.9	$	2.2	$	3.8
Earnings per share	0.4		0.6		1.0		1.1
Total performance units	1.5		2.5		3.2		4.9
Restricted stock	0.1		0.1		0.1		0.1
Total compensation expense	1.6		2.6		3.3		5.0
Less: Amount paid by unconsolidated affiliates	—		0.2		—		0.5
Net compensation expense	$	1.6	$	2.4	$	3.3	$	4.5
Income tax benefit	$	0.7	$	1.0	$	1.3	$	1.8

During thethree and six months endedJune 30, 2016, the Company issued an immaterial number of shares to satisfy restricted stock grants.

6. 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 to2012or state and local tax examinations by tax authorities for years prior to2011.  Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss.  Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

7. Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months endedJune 30, 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 June 30, 2016,

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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 June 30,				Six Months Ended June 30,
(In millions except per share data)	2016		2015		2016		2015
Net income	$	71.5	$	87.5	$	96.7	$	130.7
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.6		199.7		199.6
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.1		—		0.1		—
Diluted average common shares outstanding	199.8		199.6		199.8		199.6
Basic Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Diluted Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

8. Long-Term Debt

AtJune 30, 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%	-	0.45%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.45%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.45%	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, at100 percentof 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.

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9. Short-Term Debt and CreditFacilities

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 ofJune 30, 2016, the Company had$284.4 millionof short-term debt as compared tono balance at December 31, 2015. The following table provides information regarding the Company's revolving credit agreement at June 30, 2016.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
(In millions)
OGE Energy (B)	$	750.0	$	284.4	0.76	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0		1.7		0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0	$	286.1	0.76	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2016.

(B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  

(C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.

(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

(E) As of June 30, 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 downgradecould 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 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.

10. Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan, and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.7 million during the six months endedJune 30, 2016. The pension settlement charge did not increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

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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
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)			2016 (B)		2015 (B)		2016 (C)		2015 (C)
Service cost	$	3.5		$	3.4		$	7.9		$	7.9		$	0.1	$	0.2	$	0.2	$	0.6
Interest cost	6.1			6.6			12.7			13.0			0.1		0.1		0.2		0.3
Expected return on plan assets	(10.2		)	(11.7		)	(20.7		)	(23.5		)	—		—		—		—
Amortization of net loss	4.0			5.4			8.2			9.7			0.1		0.2		0.3		0.3
Amortization of unrecognized prior service cost (A)	—			0.1			—			0.2			—		0.1		—		0.1
Settlement	—			—			—			—			8.7		—		8.7		—
Total net periodic benefit cost	3.4			3.8			8.1			7.3			9.0		0.6		9.4		1.3
Less: Amount paid by unconsolidated affiliates	1.2			1.0			2.5			2.1			0.2		0.1		0.2		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	2.2		$	2.8		$	5.6		$	5.2		$	8.8	$	0.5	$	9.2	$	1.2

(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$11.0 millionand$3.3 millionof net periodic benefit cost recognizedduring thethree months endedJune 30, 2016and2015, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedJune 30, 2016and2015of$2.6 millionand$2.4 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thethree months endedJune 30, 2016 of $0.6 millionrelated tothe pension settlement charge of$8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thethree months endedJune 30, 2016 of $0.1 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$8.7 million.

(C) In addition to the$14.8 millionand$6.4 millionof net periodic benefit cost recognizedduring thesix months endedJune 30, 2016and2015, respectively, OG&E recognized the following:

• an increase in pension expense during thesix months endedJune 30, 2016and2015of$4.9 millionand$5.4 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thesix months endedJune 30, 2016 of $0.6 millionrelated tothe pension settlement charge of$8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thesix months endedJune 30, 2016 of $0.1 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$8.7 million.

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	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)
Service cost	$	0.1		$	0.3		$	0.4		$	0.8
Interest cost	2.4			2.5			4.7			5.1
Expected return on plan assets	(0.5		)	(0.6		)	(1.1		)	(1.2		)
Amortization of net loss	0.8			3.5			1.3			6.9
Amortization of unrecognized prior service cost (A)	(2.2		)	(4.2		)	(4.4		)	(8.3		)
Total net periodic benefit cost	0.6			1.5			0.9			3.3
Less: Amount paid by unconsolidated affiliates	—			0.3			0.1			0.6
Net periodic benefit cost (net of unconsolidated affiliates)	$	0.6		$	1.2		$	0.8		$	2.7

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

(B) In addition to the$0.6 millionand$1.2 millionof net periodic benefit cost recognizedduring thethree months endedJune 30, 2016and2015, respectively, OG&E recognized an increase in postretirement medical expense duringthethree months endedJune 30, 2016and2015of$2.0 millionand$1.5 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$0.8 millionand$2.7 millionof net periodic benefit cost recognizedduring thesix months endedJune 30, 2016and2015, respectively, OG&E recognized an increase in postretirement medical expense duringthesix months endedJune 30, 2016and2015of$4.0 millionand$2.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Capitalized portion of net periodic pension benefit cost	$	0.8	$	1.2	$	2.0	$	2.0
Capitalized portion of net periodic postretirement benefit cost	0.2		0.4		0.4		0.9

Pension Plan Funding

In July 2016, the Company contributed$20.0 millionto its Pension Plan. No additional contributions are expected in 2016.

11. Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy, and (ii) the natural gas midstream operations segment.

Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.

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The following tables summarize the results of the Company's business segments during the three and six months endedJune 30, 2016 and 2015.

Three Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	551.4	$	—		$	—		$	—		$	551.4
Cost of sales	197.7		—			—			—			197.7
Other operation and maintenance	124.8		7.8			(5.0		)	—			127.6
Depreciation and amortization	78.4		—			1.7			—			80.1
Taxes other than income	19.1		—			1.0			—			20.1
Operating income (loss)	131.4		(7.8		)	2.3			—			125.9
Equity in earnings of unconsolidated affiliates	—		16.7			—			—			16.7
Other income (expense)	7.0		—			(1.4		)	(0.1		)	5.5
Interest expense	35.0		—			1.1			(0.1		)	36.0
Income tax expense (benefit)	31.1		9.3			0.2			—			40.6
Net income (loss)	$	72.3	$	(0.4	)	$	(0.4	)	$	—		$	71.5
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2

Three Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	549.9	$	—		$	—		$	—		$	549.9
Cost of sales	210.9		—			—			—			210.9
Other operation and maintenance	115.6		0.2			(2.6		)	—			113.2
Depreciation and amortization	74.3		—			1.9			—			76.2
Taxes other than income	21.6		—			0.8			—			22.4
Operating income (loss)	127.5		(0.2		)	(0.1		)	—			127.2
Equity in earnings of unconsolidated affiliates	—		28.2			—			—			28.2
Other income (expense)	4.4		—			0.8			(0.1		)	5.1
Interest expense	37.3		—			0.8			(0.1		)	38.0
Income tax expense (benefit)	25.6		10.0			(0.6		)	—			35.0
Net income (loss)	$	69.0	$	18.0		$	0.5		$	—		$	87.5
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1

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Six Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	984.5	$	—		$	—		$	—		$	984.5
Cost of sales	375.6		—			—			—			375.6
Other operation and maintenance	241.1		8.0			(7.6		)	—			241.5
Depreciation and amortization	155.1		—			3.5			—			158.6
Taxes other than income	42.7		—			2.3			—			45.0
Operating income (loss)	170.0		(8.0		)	1.8			—			163.8
Equity in earnings of unconsolidated affiliates	—		45.0			—			—			45.0
Other income (expense)	12.3		—			(1.1		)	(0.2		)	11.0
Interest expense	70.5		—			2.0			(0.2		)	72.3
Income tax expense (benefit)	33.4		19.4			(2.0		)	—			50.8
Net income (loss)	$	78.4	$	17.6		$	0.7		$	—		$	96.7
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2

Six Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.0	$	—		$	—		$	—		$	1,030.0
Cost of sales	422.5		—			—			—			422.5
Other operation and maintenance	229.9		1.0			(6.0		)	—			224.9
Depreciation and amortization	148.1		—			4.0			—			152.1
Taxes other than income	44.7		—			2.2			—			46.9
Operating income (loss)	184.8		(1.0		)	(0.2		)	—			183.6
Equity in earnings of unconsolidated affiliates	—		59.9			—			—			59.9
Other income (expense)	7.3		—			3.3			(0.1		)	10.5
Interest expense	74.1		—			1.4			(0.1		)	75.4
Income tax expense (benefit)	31.9		18.1			(2.1		)	—			47.9
Net income (loss)	$	86.1	$	40.8		$	3.8		$	—		$	130.7
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1

12. Commitments and Contingencies

Except as set forth below, in Note13 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 Notes14and15 to the Company's Consolidated Financial Statements included in the Company's 2015Form 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 ofOG&Eare 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 itscondensedfinancial position or results of operations.The Companybelieves, however, that it is likely that the trend in

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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, on behalf of the EPA, 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 sought 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. The Sierra Club did not seek review of the case by the United States Supreme Court. OG&E considers this case now closed.

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 “Pending Regulatory Matters” in Note 13.

Other

In the normal course of business,the Companyis 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 Companyhas incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements.At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

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13. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note15to the Company's Consolidated Financial Statements included in the Company's 2015Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation

On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.

Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities.

The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement.

On July 1, 2016, the Court upheld the FERC's decision requiring removal of the rights of first refusal for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the rights of first refusal in the SPP Membership Agreement to be anticompetitive.

The Company does not believe the Court’s ruling will have any impact on existing transmission projects for which the Company has already received a notice to construct from the SPP.  The Company intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.

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.

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

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the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.

In December 2012, the OCC issued an order approving the recovery of costs associated with the Demand Programs, including the lost revenues associated with the SmartHours program, subject to the PUD Staff's review.

In March 2014, the PUD Staff began their review of the Demand Program costs, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the 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 millionannually) in accordance with the agreement that it believed had been reached with the PUD Staff.

In April 2015, the 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 PUD Staff recommends the OCC approve the PUD Staff's 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 millionfrom 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 that OG&E will recover$10.1 millionof lost revenues associated with 2013,$11.6 millionassociated with 2014 and$14.9 millionassociated with 2015. Through June 30, 2016, OG&E had collected from its customers approximately$15.2 million of the$36.6 millionof lost revenues for 2013, 2014 and 2015.

A hearing on the 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 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$21.4 millionof 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 Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also 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. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015, approximately seven months after OG&E filed its application, 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,

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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 Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP. 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 did not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates.On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Two parties to the proceeding have appealed the OCC's decision to the Oklahoma Supreme Court.

OG&E anticipates the total cost of dry scrubbers will be $547.5 million. As of June 30, 2016, OG&E had incurred$116.8 millionof construction work in progress on the dry scrubbers.OG&E anticipates the combustion turbines for the Mustang Modernization Plan will be$424.9 million. As ofJune 30, 2016, OG&E has incurred $103.6 millionon the Mustang Modernization Plan.

Mustang Modernization Plan-Arkansas

On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility.  Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas.  The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings.  On July 28, 2016, OG&E filed a motion to dismiss the APSC Mustang proceeding.  OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service.

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 millionand a10.25 percentreturn on equity based on a common equity percentage of53 percent. The rate case was based on a June 30, 2015 test year and included recovery of$1.6 billionof 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 millionannual rate increase based on a return on equity of9.25 percentand a common equity percentage of 53.0 percent.  Included in the PUD Staff's recommendation is a reduction of$33.0 millionto 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 millionbased on a return on equity of 9.25 percentand a common equity percentage of50 percent, as well as a recommendation to reduce rates$13.7 million

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based on a return on equity of8.90 percentand a common equity percentage of53 percent.  Included in the Attorney General's recommendation is a reduction of$20.9 millionto OG&E’s requested increase for depreciation and plant dismantlement.

The Oklahoma Industrial Electric Consumers recommended a$47.9 millionannual rate decrease based on a return on equity of9.00 percentand a common equity percentage of53 percent.  Included in the Oklahoma Industrial Electric Consumers' recommendation is a reduction of$52.5 millionto 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. On July 1, 2016, OG&E implemented an annual interim rate increase of$69.5 millionwhile simultaneously reducing fuel costs billed to customers. The interim rates are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case.

Arkansas Rate Case Filing

OG&E intends to file a general rate case in Arkansas with the APSC during the third quarter of 2016.

Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations.

Introduction

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

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

On August 3, 2016, Enable announced a quarterly dividend distribution of$0.3180per unit on its outstanding common and subordinated units, representing the same dividend distribution as the previous quarter.

Overview

Company Strategy

The Company'smission, through OG&E and its equity interest in Enable, is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructureand meet individual customer's needs for energy and related services, focusing on safety, efficiency, reliability, customer service and risk management. The Company's corporate strategy is to continue to maintain its existing business mix and diversified asset position of its regulated electric utility business and interest in a publicly traded midstream company,while providing competitive energy products and services to customers as well as seeking growth opportunities in both businesses.

Additionally, the Company wants to achieve a premium valuation of its businesses relative to its peers, grow earnings per share with a stable earnings pattern, create a high performance culture and achieve desired outcomes with target stakeholders. The Company's financial objectives include a long-term annual earnings growth rate for OG&E of three to five percent on a

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weather-normalized basis, maintaining a strong credit rating as well as targeting dividend increases of approximately 10 percent annually through 2019. The targeted annual dividend increase has been determined after consideration of numerous factors, including the largely retail composition of the Company's shareholder base, the Company's financial position, the Company's growth targets and the composition of the Company's assets and investment opportunities. The Company also relies on cash distributions from its investment in Enable to fund its capital needs and support future dividend growth. The Company believes it can accomplish these financial objectives by, among other things, pursuing multiple avenues to build its business, maintaining a diversified asset position, continuing to develop a wide range of skills to succeed with changes in its industries, providing products and services to customers efficiently, managing risks effectively and having strong regulatory and legislative relationships.

Summary of Operating Results

Three Months Ended June 30, 2016as Compared toThree Months Ended June 30, 2015

Net income attributable to the Company was$71.5 million, or$0.35per diluted share, during thethree months endedJune 30, 2016as compared to$87.5 million, or$0.44per diluted share, during the same period in2015. Thedecreasein net income of$16.0 million, or$0.09 per diluted share, during thethree months endedJune 30, 2016as compared to the same period in2015was primarily due to:

• a decrease in net income attributable to OGE Holdings of $18.4 million, or $0.10 per diluted share of the Company's common stock, primarily due to a decrease in earnings of unconsolidated affiliates, an increase in operations and maintenance expense, resulting from the settlement of the Supplemental Executive Retirement Plan and the Restoration of Retirement Income Plan, as described in Note 10, and an increase in state income tax expense due to a change in Louisiana tax law, partially offset by a decrease in income taxes resulting from lower taxable income; offset in part by

• an increase in net income at OG&E of $3.3 million, or $0.02 per diluted share of the Company's common stock, primarily due to an increase in gross margin, higher other income, lower taxes other than income and decreased interest expense partially offset by an increase in other operation and maintenance expense, higher income tax expense and additional depreciation and amortization expense due to additional assets placed into service.

Six Months Ended June 30, 2016as Compared toSix Months Ended June 30, 2015

Net income attributable to the Company was$96.7 million, or$0.48per diluted share, during thesix months endedJune 30, 2016as compared to$130.7 million, or$0.66per diluted share, during the same period in2015. Thedecreasein net income of$34.0 million, or$0.18 per diluted share, during thesix months endedJune 30, 2016as compared to the same period in2015was primarily due to:

• a decrease in net income attributable to OGE Holdings of $23.2 million, or $0.12 per diluted share of the Company's common stock, primarily due to a decrease in earnings of unconsolidated affiliates, an increase in operations and maintenance expense, resulting from the settlement of the Supplemental Executive Retirement Plan and the Restoration of Retirement Income Plan, as described in Note 10, and an increase in state income tax expense due to a change in Louisiana tax law, partially offset by a decrease in income taxes resulting from lower taxable income; and

• a decrease in net income at OG&E of $7.7 million, or $0.04 per diluted share of the Company's common stock, primarily due to an increase in other operation and maintenance expense, higher depreciation and amortization expense due to additional assets being placed into service and an increase in income tax expense. These decreases were partially offset by higher other income, an increase in gross margin, a decrease in interest expense and lower taxes other than income; and

• a decrease in net income at the Company of $3.1 million, or $0.02 per diluted share of the Company's common stock, primarily due to an increase in losses associated with the deferred compensation plan.

Recent Developments

CenterPoint had previously announced that it was evaluating strategic alternatives for its investment in Enable.  On July 18, 2016, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided notice to the Company of CenterPoint’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner.  Under the terms of the right of first offer, the Company has 30 days from receipt of the notice from CenterPoint

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to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint Energy Resources Corp. common units and subordinated units.  If the Company were to make an offer under the right of first offer, then CenterPoint would have 30 days to accept such offer.  The Company is currently evaluating its options with respect to the right of first offer.

2016 Outlook

The Company's 2016 earnings guidance is between approximately $344.0 million to $366.0 million of net income, or $1.72 to $1.83 per average diluted share. The guidance assumes, among other things, approximately 200 million average diluted shares outstanding, normal weather for the year and full recovery of the lost revenues associated with the SmartHours program as described in Note 13 to the Notes to Condensed Consolidated Financial Statements. See the Company's 2015Form 10-K for other key factors and assumptions underlying its 2016 earnings guidance.

Non-GAAP Financial Measures

Gross margin is defined by OG&E as operating revenues less fuel, purchased power and certain transmission expenses. Gross margin is a non-GAAP financial measure because it excludes depreciation and amortization, and other operation and maintenance expenses. Expenses for fuel and purchased power are recovered through fuel adjustment clauses and as a result changes in these expenses are offset in operating revenues with no impact on net income. OG&E believes gross margin provides a more meaningful basis for evaluating its operations across periods than operating revenues because gross margin excludes the revenue effect of fluctuations in these expenses. Gross margin is used internally to measure performance against budget and in reports for management and the Board of Directors. OG&E's definition of gross margin may be different from similar terms used by other companies.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for thethree and six months endedJune 30, 2016as compared to the same period in2015and the Company's consolidated financial position atJune 30, 2016. Due to seasonal fluctuations and other factors, the Company'soperating results for thethree and six months endedJune 30, 2016are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2016or for any future period.The following information should be read in conjunction with theCondensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions except per share data)	2016		2015		2016		2015
Net income	$	71.5	$	87.5	$	96.7	$	130.7
Basic average common shares outstanding	199.7		199.6		199.7		199.6
Diluted average common shares outstanding	199.8		199.6		199.8		199.6
Basic earnings per average common share	$	0.35	$	0.44	$	0.48	$	0.66
Diluted earnings per average common share	$	0.35	$	0.44	$	0.48	$	0.66
Dividends declared per common share	$	0.27500	$	0.25000	$	0.55000	$	0.50000

Results by Business Segment

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2016			2015		2016		2015
Net income (loss) attributable to OGE Energy
OG&E (Electric Utility)	$	72.3		$	69.0	$	78.4	$	86.1
OGE Holdings (Natural Gas Midstream Operations)	(0.4		)	18.0		17.6		40.8
Other Operations (A)	(0.4		)	0.5		0.7		3.8
Consolidated net income	$	71.5		$	87.5	$	96.7	$	130.7

(A) Other Operations primarily includes the operations of the holding company and consolidating eliminations.

The following discussion of results of operations by business segment includes intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements. 

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OG&E (Electric Utility)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Dollars in millions)	2016		2015		2016		2015
Operating revenues	$	551.4	$	549.9	$	984.5	$	1,030.0
Cost of sales	197.7		210.9		375.6		422.5
Other operation and maintenance	124.8		115.6		241.1		229.9
Depreciation and amortization	78.4		74.3		155.1		148.1
Taxes other than income	19.1		21.6		42.7		44.7
Operating income	131.4		127.5		170.0		184.8
Allowance for equity funds used during construction	3.7		1.7		5.3		3.2
Other income	4.4		3.3		8.4		5.0
Other expense	1.1		0.6		1.4		0.9
Interest expense	35.0		37.3		70.5		74.1
Income tax expense	31.1		25.6		33.4		31.9
Net income	$	72.3	$	69.0	$	78.4	$	86.1
Operating revenues by classification
Residential	$	219.6	$	214.0	$	398.1	$	408.6
Commercial	143.1		140.6		245.8		246.5
Industrial	48.8		49.3		87.0		91.0
Oilfield	38.8		42.1		71.1		79.1
Public authorities and street light	51.5		51.3		87.6		90.7
Sales for resale	0.1		9.0		0.2		20.8
System sales revenues	501.9		506.3		889.8		936.7
Integrated market	10.7		11.0		19.8		21.3
Other	38.8		32.6		74.9		72.0
Total operating revenues	$	551.4	$	549.9	$	984.5	$	1,030.0
Reconciliation of gross margin to revenue:
Operating revenues	$	551.4	$	549.9	$	984.5	$	1,030.0
Cost of sales	197.7		210.9		375.6		422.5
Gross margin	$	353.7	$	339.0	$	608.9	$	607.5
MWH sales by classification (In millions)
Residential	2.0		2.0		4.1		4.3
Commercial	2.0		2.0		3.6		3.6
Industrial	0.9		0.9		1.8		1.8
Oilfield	0.8		0.8		1.6		1.7
Public authorities and street light	0.8		0.8		1.5		1.5
Sales for resale	—		0.2		—		0.5
System sales	6.5		6.7		12.6		13.4
Integrated market	0.4		0.5		0.8		0.7
Total sales	6.9		7.2		13.4		14.1
Number of customers	829,779		819,483		829,779		819,483
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	2.262		2.704		2.157		2.664
Coal	2.293		2.174		2.290		2.144
Total fuel	2.122		2.220		2.034		2.209
Total fuel and purchased power	2.735		2.891		2.675		2.896
Degree days (A)
Heating - Actual	159		143		1,711		1,984
Heating - Normal	203		203		2,001		2,001
Cooling - Actual	620		610		632		621
Cooling - Normal	625		625		638		638

(A) Degree days are calculated as follows:  The high and low degrees of a particular day are added together and then averaged.  If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day.  If the calculated average is below 65 degrees,

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then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day.  The daily calculations are then totaled for the particular reporting period.

Three Months Ended June 30, 2016as Compared toThree Months Ended June 30, 2015

OG&E's net incomeincreased$3.3 million, or4.8 percent, during thethree months endedJune 30, 2016as compared to the same period in2015primarily due to higher gross margin, higher other income, lower taxes other than income and lower interest expense partially offset by higher other operation and maintenance expense, higher income tax expense and higher depreciation and amortization expense.

Operating revenues were$551.4 millionduring thethree months endedJune 30, 2016as compared to$549.9 millionduring the same period in2015, an increaseof$1.5 million, or0.3 percent. Cost of sales were$197.7 millionduring thethree months endedJune 30, 2016as compared to$210.9 millionduring the same period in2015, a decreaseof$13.2 million, or6.3 percent. Gross margin was$353.7 millionduring thethree months endedJune 30, 2016as compared to$339.0 millionduring the same period in2015, an increaseof$14.7 million, or4.3 percent. The below factors contributed to the change in gross margin:

(In millions)	Change
Wholesale transmission revenue (A)	$	7.4
Quantity variance (primarily weather)	6.6
Price variance (B)	5.5
Non-residential demand and related revenues	(0.1		)
New customer growth	(0.4		)
Other	(0.6		)
Expiration of AVEC contract (C)	(3.7		)
Change in gross margin	$	14.7

(A) Increased primarily due to a true up for the base plan projects in the SPP formula rate for 2014 and 2015 as well as a true up for Network Integration Transmission Services in the SPP formula rate for 2015.

(B) Increased primarily due to the reversal of a reserve for gas transportation charges offset in part by the pricing impact of weather related sales.

(C) On June 30, 2015, the wholesale power contract with AVEC expired.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.Fuel expense was$87.0 millionduring thethree months endedJune 30, 2016as compared to$105.9 millionduring the same period in2015, a decreaseof$18.9 million, or17.8 percent, primarily due to a decrease in generation due to the expiration of the wholesale power contract with AVEC in June 2015 and a decrease in natural gas prices. Purchased power costs were$97.7 millionduring thethree months endedJune 30, 2016as compared to$94.1 millionduring the same period in2015, an increaseof$3.6 million, or3.8 percent, primarily due to an increase of$4.1 millionin purchases from the SPP partially offset by a decrease of $0.3 millionin wind purchased power.Transmission expense is charged to OG&E by the SPP for the utilization of transmission systems owned by other SPP members and is recovered from retail customers through the SPP Cost Tracker in Oklahoma and through the Transmission Cost Rider in Arkansas. Transmission related charges were$13.0 millionduring thethree months endedJune 30, 2016as compared to$10.9 millionduring the same period in2015, an increaseof$2.1 million, or19.3 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

The actual cost of fuel used in electric generation and certain purchased power costs are passed through to OG&E's customers through fuel adjustment clauses. The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to its affiliate, Enable.

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Operating Expenses

Other operation and maintenance expense was$124.8 millionduring thethree months endedJune 30, 2016as compared to$115.6 millionduring the same period in2015, an increaseof$9.2 million, or8.0 percent. The below factors contributed to the change in other operation and maintenance expense:

(In millions)	Change
Corporate allocations and overheads (A)	$	3.9
Maintenance at power plants (B)	2.2
Vegetation management (C)	1.9
Contract professional services (D)	1.3
Other	(0.1		)
Change in other operation and maintenance expense	$	9.2

(A) Increased primarily due to additional information technology and facility direct support.

(B) Increased primarily due to timing of work performed at the power plants.

(C) Increased primarily due to timing of vegetation management.

(D) Increased primarily due to increased engineering services.

Depreciation and amortization expense was$78.4 millionduring thethree months endedJune 30, 2016as compared to$74.3 millionduring the same period in2015, an increaseof$4.1 million, or5.5 percent, primarily due to additional assets being placed in service.

Taxes other than income was$19.1 millionduring thethree months endedJune 30, 2016as compared to$21.6 millionduring the same period in2015, a decreaseof$2.5 million, or11.6 percent, primarily due to lower assessed ad valorem taxes and increased capitalized ad valorem taxes.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was$3.7 millionduring thethree months endedJune 30, 2016as compared to$1.7 millionduring the same period in2015, an increase of $2.0 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other Income.Other income was $4.4 million during the three months endedJune 30, 2016 as compared to $3.3 million during the same period in 2015, an increase of $1.1 million, or 33.3 percent, primarily due to an increase in the tax gross up related to higher allowance for funds used during construction.

Interest Expense.Interest expense was$35.0 millionduring thethree months endedJune 30, 2016as compared to$37.3 millionduring the same period in2015, a decrease of $2.3 million, or 6.2 percent, primarily due to a decrease in interest expense related to the retirement of$110.0 millionlong-term debt in January 2016 and increased allowance for borrowed funds used during construction.

Income Tax Expense.Income tax expense was$31.1 millionduring thethree months endedJune 30, 2016as compared to$25.6 millionduring the same period in2015, an increaseof$5.5 million, or21.5 percent, primarily due to higher pre-tax income and a reduction in tax credits generated.

Six Months Ended June 30, 2016as Compared toSix Months Ended June 30, 2015

OG&E's net incomedecreased$7.7 million, or8.9 percent, during thesix months endedJune 30, 2016as compared to the same period in2015primarily due to higher other operation and maintenance expense, higher depreciation and amortization expense and higher income tax expense partially offset by higher other income, higher gross margin, lower interest expense and lower taxes other than income.

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Operating revenues were$984.5 millionduring thesix months endedJune 30, 2016as compared to$1,030.0 millionduring the same period in2015, a decreaseof$45.5 million, or4.4 percent. Cost of sales were$375.6 millionduring thesix months endedJune 30, 2016as compared to$422.5 millionduring the same period in2015, a decreaseof$46.9 million, or11.1 percent. Gross margin was$608.9 millionduring thesix months endedJune 30, 2016as compared to$607.5 millionduring the same period in2015, an increaseof$1.4 million, or0.2 percent. The below factors contributed to the change in gross margin:

(In millions)	Change
Price variance (A)	$	10.1
Wholesale transmission revenue (B)	6.1
New customer growth	0.1
Non-residential demand and related revenues	(1.7		)
Other	(2.0		)
Quantity variance (primarily weather)	(2.2		)
Expiration of AVEC contract (C)	(9.0		)
Change in gross margin	$	1.4

(A) Increased primarily due to the reversal of a reserve for gas transportation charges in addition to the pricing impact of weather related sales.

(B) Increased primarily due to a true up for the base plan projects in the SPP formula rate for 2014 and 2015 as well as a true up for Network Integration Transmission Services in the SPP formula rate for 2015.

(C) On June 30, 2015, the wholesale power contract with AVEC expired.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.Fuel expense was$165.6 millionduring thesix months endedJune 30, 2016as compared to$219.7 millionduring the same period in2015, a decreaseof$54.1 million, or24.6 percent, primarily due to a decrease in generation due to the expiration of the wholesale power contract with AVEC in June 2015 and a decrease in natural gas prices.Purchased power costs were$184.0 millionduring thesix months endedJune 30, 2016as compared to$180.6 millionduring the same period in2015, an increaseof$3.4 million, or1.9 percent, primarily due to an increase of$3.1 millionin wind purchased power and$3.0 millionin cogeneration purchases partially offset by a decrease of$2.7 millionin purchases from the SPP. Transmission expense is charged to OG&E by the SPP for the utilization of transmission systems owned by other SPP members and is recovered from retail customers through the SPP Cost Tracker in Oklahoma and through the Transmission Cost Rider in Arkansas. Transmission related charges were$26.0 millionduring thesix months endedJune 30, 2016as compared to$22.2 millionduring the same period in2015, an increaseof$3.8 million, or17.1 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

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Operating Expenses

Other operation and maintenance expense was$241.1 millionduring thesix months endedJune 30, 2016as compared to$229.9 millionduring the same period in2015, an increaseof$11.2 million, or4.9 percent. The below factors contributed to the change in other operation and maintenance expense:

(In millions)	Change
Corporate allocations and overheads (A)	$	4.0
Vegetation management (B)	3.3
Maintenance at power plants (C)	2.9
Salaries and wages (D)	2.6
Contract professional services	1.3
Other	0.2
Capitalized labor (E)	(1.5		)
Software expense	(1.6		)
Change in other operation and maintenance expense	$	11.2

(A) Increased primarily due to additional information technology and facility direct support.

(B) Increased primarily due to timing of vegetation management.

(C) Increased primarily due to timing of work performed at the power plants.

(D) Increased primarily due to annual salary increases and an increase in incentive compensation.

(E) Decreased primarily due to reduced capitalized labor related to storms.

Depreciation and amortization expense was$155.1 millionduring thesix months endedJune 30, 2016as compared to$148.1 millionduring the same period in2015, an increaseof$7.0 million, or4.7 percent, primarily due to additional assets being placed in service.

Taxes other than income was $42.7 millionduring thesix months endedJune 30, 2016as compared to $44.7 millionduring the same period in 2015, a decrease of $2.0 million, or4.5 percent, primarily due to lower assessed ad valorem taxes and increased capitalized ad valorem taxes.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was$5.3 millionduring thesix months endedJune 30, 2016as compared to$3.2 millionduring the same period in2015, an increase of $2.1 million, or 65.6 percent, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other Income.Other income was$8.4 millionduring thesix months endedJune 30, 2016as compared to$5.0 millionduring the same period in2015, an increase of $3.4 million, or 68.0 percent, primarily due to increased guaranteed flat bill margins and an increase in the tax gross up related to higher allowance for funds used during construction.

Interest Expense.Interest expense was$70.5 millionduring thethree months endedJune 30, 2016as compared to74.1 millionduring the same period in2015, a decrease of $3.6 million, or 4.9 percent, primarily due to a decrease in interest expense related to the retirement of$110.0 millionlong-term debt in January 2016 and increased allowance for borrowed funds used during construction.

Income Tax Expense.Income tax expense was$33.4 millionduring thesix months endedJune 30, 2016as compared to$31.9 millionduring the same period in2015, an increaseof$1.5 million, or4.7 percent, primarily due to a reduction in tax credits generated partially offset by lower pretax income.

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OGE Holdings (Natural Gas Midstream Operations)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015
Operating revenues	$	—		$	—		$	—		$	—
Cost of sales	—			—			—			—
Other operation and maintenance	7.8			0.2			8.0			1.0
Depreciation and amortization	—			—			—			—
Taxes other than income	—			—			—			—
Operating income (loss)	(7.8		)	(0.2		)	(8.0		)	(1.0		)
Equity in earnings of unconsolidated affiliates	16.7			28.2			45.0			59.9
Income before taxes	8.9			28.0			37.0			58.9
Income tax expense	9.3			10.0			19.4			18.1
Net income (loss) attributable to OGE Holdings	$	(0.4	)	$	18.0		$	17.6		$	40.8

Three Months Ended June 30, 2016as Compared toThree Months Ended June 30, 2015

OGE Holding's net income decreased$18.4 million for the three months endedJune 30, 2016 as compared to the same period in 2015, primarily due to a $11.5 million decrease in equity in earnings of Enable, an increase in operations and maintenance expense, resulting from the settlement of the Supplemental Executive Retirement Plan and the Restoration of Retirement Income Plan, as described in Note 10, and an increase in state income tax due to a change in Louisiana tax law, partially offset by a decrease in income taxes resulting from lower taxable income. Enable reported lower gross margins due to lower commodity prices and an increase in unrealized losses on condensate and NGL derivatives. In addition to lower gross margins, Enable reported increased depreciation and amortization expense, increased interest expense and increased preferred unit distributions, partially offset by lower operating and maintenance expense.

As discussed above, the Company reported a settlement of its Supplemental Executive Retirement Plan and its non-qualified Restoration of Retirement Income Plan. As a result, OGE Holdings recorded pension settlement charges of $7.9 million in the second quarter of 2016.

Six Months Ended June 30, 2016as Compared toSix Months Ended June 30, 2015

OGE Holding's net income decreased$23.2 million for the six months endedJune 30, 2016 as compared to the same period in 2015, primarily due to a $14.9 milliondecrease in equity in earnings of Enable, an increase in operations and maintenance expense, resulting from the settlement of the Supplemental Executive Retirement Plan and the Restoration of Retirement Income Plan, as described in Note 10, and an increase in state income tax due to a change in Louisiana tax law, partially offset by a decrease in income taxes resulting from lower taxable income. Enable reported lower gross margins due to lower commodity prices, lower firm transportation revenues and a decrease in storage demand fees, along with an increase in unrealized losses on condensate and NGL derivatives. In addition to lower gross margins, Enable reported increased depreciation and amortization expense, increased interest expense and increased preferred unit distributions, partially offset by lower operating and maintenance expense.

As discussed above, the Company reported a settlement of its Supplemental Executive Retirement Plan and its non-qualified Restoration of Retirement Income Plan. As a result, OGE Holdings recorded pension settlement charges of $7.9 million in the second quarter of 2016.

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Reconciliation of Equity in Earnings of Unconsolidated Affiliates

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three and six months endedJune 30, 2016 as compared to the same period in 2015:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
OGE's share of Enable net income	$	9.1	$	20.6	$	30.4	$	44.4
Amortization of basis difference	3.0		3.6		5.9		7.1
Elimination of Enogex Holdings fair value and other adjustments	4.6		4.0		8.7		8.4
Equity in earnings of unconsolidated affiliates	$	16.7	$	28.2	$	45.0	$	59.9

Enable Results of Operations

The following table represents summarized financial information of Enable for the three and six months endedJune 30, 2016 as compared to the same period in 2015:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of natural gas and natural gas liquids	254		277		449		569
Operating income	57		93		160		197
Net income	35		77		121		168

Enable Operating Data

The following table presents Enable's operating data for the three and six months endedJune 30, 2016 as compared to the same period in 2015:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
Gathered volumes - TBtu/d	3.10	3.19	3.07	3.19
Transportation volumes - TBtu/d	4.87	4.97	4.99	5.34
Natural gas processed volumes - TBtu/d	1.76	1.84	1.78	1.76
NGLs sold - million gallons/d (A)(B)	83.80	75.91	80.15	71.68

(A) Excludes condensate.

(B) NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

Off-Balance Sheet Arrangement

There have been no significant changes in the Company's off-balance sheet arrangement from that discussed in the Company's 2015Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

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Liquidity and Capital Resources

Working Capital

Working capital is defined as the difference in current assets and current liabilities. The Company's working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for maintenance and expansion activity, inventory levels and fuel recoveries.

Cash and Cash Equivalents. There was no balance in Cash and Cash Equivalents at June 30, 2016 compared to a balance of $75.2 million at December 31, 2015, primarily due to the use of cash and payment of long-term debt of $110.0 million that matured in January 2016.

Accounts Receivable and Accrued Unbilled Revenues.The balance of Accounts Receivable and Accrued Unbilled Revenues was$254.0 millionand$228.3 millionatJune 30, 2016andDecember 31, 2015, respectively,an increaseof$25.7 million, or11.3 percent, primarily due toan increase in billings to OG&E's retail customers reflecting higher usage due to warmer weather in June 2016 as compared to December 2015.

Other Current Assets. The balance of Other Current Assets was $75.9 million and $55.6 million at June 30, 2016 and December 31, 2015, respectively, an increase of $20.3 million, or 36.5 percent, primarily due to reduced revenue collections from customers and increased revenue requirements that are not included in current rates.

Short-Term Debt. The balance of Short-term Debt was $284.4 million at June 30, 2016 compared to no balance at December 31, 2015. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.

Accounts Payable. The balance of Accounts Payable was $159.7 million and $262.5 million at June 30, 2016 and December 31, 2015, respectively, a decrease of $102.8 million, or 39.2 percent, primarily due to the timing of vendor payments and a decrease in accruals.

Accrued Compensation. The balance of Accrued Compensation was $35.7 million and $54.4 million at June 30, 2016 and December 31, 2015, respectively, a decrease of 18.7 million, or 34.4 percent, primarily resulting from the payment of retirement restoration benefits at June 30, 2016.

Long-Term Debt Due Within One Year. There was no balance of Long-term Debt Due Within One Year at June 30, 2016 compared to a balance of $110.0 million at December 31, 2015due to long-term debt that matured in January 2016.

Fuel Clause Recoveries.The balance of Fuel Clause Over Recoveries was$41.3 million and $61.3 million at June 30, 2016 and December 31, 2015, respectively, a decrease of $20.0 million, or 32.6 percent, primarily due to lower amounts billed to OG&E retail customers as compared to the actual cost of fuel and purchased power.

Cash Flows

	Six Months Ended
	June 30,						2016 vs. 2015
(In millions)	2016			2015			$ Change			% Change
Net cash provided from operating activities	$	166.0		$	305.8		$	(139.8	)	(45.7	)%
Net cash used in investing activities	(305.7		)	(225.7		)	(80.0		)	35.4	%
Net cash provided from (used in) financing activities	64.5			(85.6		)	150.1			*

* Change is greater than 100 percent.

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Operating Activities

Thedecrease of $139.8 million, or 45.7 percent, in net cash provided from operating activities during thesix months endedJune 30, 2016as compared to the same period in2015was primarily due to higher fuel refunds during thesix months endedJune 30, 2016as compared to higher fuel recoveries in2015 at OG&E, the payment of retirement restoration benefits in the second quarter of 2016, a decrease in accrued taxes due to ad valorem accruals at OG&E and a decrease in cash received from transmission revenue at OG&E.

Investing Activities

Theincrease of $80.0 million, or 35.4 percent, in net cashused ininvesting activities during thesix months endedJune 30, 2016as compared to the same period in2015was primarily due toan increase in capital expenditures related to environmental projects at OG&E partially offset by an increase in investments related to return of capital from Enable.

Financing Activities

Theincrease of $150.1 millionin net cash provided from financing activitiesduring thesix months endedJune 30, 2016as compared to the same period in2015was primarily due to an increase in short-term debt partially offset by the payment of long-term debt in January of 2016.

Future Capital Requirements and Financing Activities

The Company's primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, fuel clause under and over recoveries and other general corporate purposes. The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.

Capital Expenditures

The Company's consolidated estimates of capital expenditures for the years 2016 through 2020 are shown in the following table.These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company's business) plus capital expenditures for known and committed projects. Estimated capital expenditures for Enable are not included in the table below.

(In millions)	2016		2017		2018		2019		2020
OG&E Base Transmission	$	50	$	30	$	30	$	30	$	30
OG&E Base Distribution	185		175		175		175		175
OG&E Base Generation	45		75		75		75		75
OG&E Other	40		25		25		25		25
Total Base Transmission, Distribution, Generation and Other	320		305		305		305		305
OG&E Known and Committed Projects:
Transmission Projects:
Other Regionally Allocated Projects (A)	45		30		20		20		20
Large SPP Integrated Transmission Projects (B) (C)	20		150		20		—		—
Total Transmission Projects	65		180		40		20		20
Other Projects:
Environmental - low NOX burners (D)	25		10		—		—		—
Environmental - dry scrubbers (D)	80		170		100		25		—
Combustion turbines - Mustang	155		160		25		—		—
Environmental - natural gas conversion (D)	—		20		30		25		—
Allowance of funds used during construction and ad valorem taxes	20		55		40		—		—
Total Other Projects	280		415		195		50		—
Total Known and Committed Projects	345		595		235		70		20
Total	$	665	$	900	$	540	$	375	$	325

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(A) Typically 100kV to 299kV projects. Approximately 30 percent of revenue requirement allocated to SPP members other than OG&E.

(B) Typically 300kV and above projects. Approximately 85 percent of revenue requirement allocated to SPP members other than OG&E.

(C)	Project Type	Project Description	Estimated Cost (In millions)	Projected In-Service Date
	Integrated Transmission Project	30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation. Approximately $5.0 million of the estimated cost has been spent prior to 2016.	$45	Late 2017
	Integrated Transmission Project	126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation; construction of the Mathewson substation on this transmission line. Approximately $55.0 million of the estimated cost associated with the Mathewson to Cimarron line and substations will go into service in 2016; $35.0 million has been spent prior to 2016.	$190	Mid 2018

(D) Represent capital costs associated with OG&E’s ECP to comply with the EPA’s MATS and Regional Haze Rule. More detailed discussion regarding the Regional Haze Rule and OG&E’s ECP can be found in Note 13 of Notes to Condensed Consolidated Financial Statements under "Environmental Compliance Plan" in Item 1 of Part I of this Form 10-Q, and under “Environmental Laws and Regulations” within “Management's Discussion and Analysis of Financial Condition and Results of Operations” under Part I, Item 2 of this Form 10-Q.

Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets, will be evaluated based on their impact upon achieving the Company's financial objectives.

Pension Plan Funding

In July 2016, the Company contributed$20.0 millionto its Pension Plan. No additional contributions are expected in 2016.

Security Ratings

Access to reasonably priced capital is dependent in part on credit and security ratings.Generally, lower ratings lead to higher financing costs.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 downgradecould also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post collateral or letters of credit.

A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt, proceeds fromother offerings and distributions from Enable will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper)to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

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Short-Term Debt and CreditFacilities

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreement. The Company has revolving credit facilities totaling in the aggregate $1,150.0 million. These bank facilities can also be used asletter of credit facilities.  As ofJune 30, 2016, the Company had$284.4 millionof short-term debt as compared tono balance at December 31, 2015. The average balance of short-term debt during the six months endedJune 30, 2016 was $201.9 million at a weighted-average interest rate of 0.74 percent. The maximum month-end balance of short-term debt during the six months endedJune 30, 2016 was $299.6 million. AtJune 30, 2016, there were$1.7 millionsupporting letters of credit at a weighted-average interest rate of0.95 percent. At June 30, 2016, the Company had $863.9 millionof net available liquidity under its revolving credit agreements.  OG&E has the necessary regulatory approvals to incur up to$800.0 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.  At June 30, 2016, the Company had no balance in cash and cash equivalents.  See Note9of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

Quarterly Distributions by Enable

Pursuant to the Enable Limited Partnership Agreement, during the three and six months endedJune 30, 2016, Enable made distributions of approximately $35.3 million and $70.6 million, respectively, to the Company. On June 22, 2016, Enable's Limited Partnership Agreement was amended to change the last permitted distribution date from 45 days to 60 days after the close of each quarter. Enable's General Partner Agreement was amended to change the distribution deadline from 50 days to five days following distributions by Enable.

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management's Discussion and Analysis.In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could have a material effect on the Company's Condensed Consolidated Financial Statements.  However, the Company believes it has taken reasonable positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.

In management's opinion, the areas of the Company where the most significant judgment is exercised for all Company segments includes the determination of Pension Plan assumptions, income taxes, contingency reserves, asset retirement obligations and depreciable lives of property, plant and equipment. For the electric utility segment, significant judgment is also exercised in the determination of regulatory assets and liabilities and unbilled revenues. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company's Audit Committee and are discussed in detail in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's 2015Form 10-K.

Commitments and Contingencies

In the normal course of business,the Companyis 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 Companyhas 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 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. See Notes 12 and 13 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q for a discussion of the Company's commitments and contingencies.

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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. These environmental laws and regulations are discussed in detail in Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's 2015Form 10-K. Except as set forth below, there have been no material changes to such items.

OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a pre-approval plan to handle state and Federally mandated environmental upgrades and, upon approval of the plan by the OCC, OG&E would be entitled to recover through a rate rider the costs of the environmental upgrades from its Oklahoma retail customers when the upgrades were placed in service under House Bill 1910, which was enacted into law in May 2005.

Air

Federal Clean Air Act Overview

OG&E’s operations are subject to the Federal Clean Air Act as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating units, and also impose various monitoring and reporting requirements.  Such laws and regulations may require that OG&E obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations or install emission control equipment. OG&E will likely be required to incur certain capital expenditures in the future for air pollution control equipment and technology in connection with obtaining and maintaining operating permits and approvals for air emissions.

Regional Haze Control Measures

The EPA's 2005 Regional Haze Rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States that may be impacted by air pollutant emissions.

On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with Regional Haze Rule. On December 28, 2011, the EPA issued a final Regional Haze Rule for Oklahoma in which it rejected the SO₂portion of the previously submitted Oklahoma SIP and issued a FIP in its place. OG&E and the State of Oklahoma's subsequent appeal of the FIP with the Tenth Circuit of Appeals and the U.S. Supreme Court ended on May 27, 2014 when the Supreme Court denied Petition for Certiorari, upholding the EPA's FIP for SO₂. The FIP compliance date is now January 4, 2019.

On December 9, 2015, the EPA released a final rule partially disapproving the revisions to the 2010 Oklahoma SIP for Regional Haze Rule and promulgated FIPs in their place for Oklahoma and Texas. The EPA disapproved portions of the Oklahoma SIP related to the establishment of reasonable progress goals for the Class I area located within the state and promulgated revised reasonable progress goals based on the FIP implementation in Texas. As a result, no further requirements are required in Oklahoma to meet the 2018 reasonable progress goals for Oklahoma.

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also 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. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015, approximately seven months after OG&E filed its application, and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

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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 Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP. 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 did not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates.On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Two parties to the proceeding have appealed the OCC's decision to the Oklahoma Supreme Court.

As of June 30, 2016, OG&E had incurred $116.8 millionof construction work in progress on the dry scrubbers.

Cross-State Air Pollution Rule

In August 2011, the EPA finalized its CSAPR that required27states in the eastern half of the United States to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. In December 2011, the EPA published a supplemental CSAPR, which would makesixadditional states, including Oklahoma, subject to the CSAPR for NO_X emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NO_X emissions from its electrical generating units within the state beginning in 2012. In response to legal challenges of the final rule on December 30, 2011, the U.S. Court of Appeals issued a stay of the rule, which includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the Court of Appeals vacated the CSAPR and ordered the EPA to promulgate a replacement rule. On April 29, 2014, the U.S. Supreme Court reversed the decision by the Court of Appeals. On October 23, 2014, the Court of Appeals for the District of Columbia Circuit granted the EPA's request that the court lift the stay of the CSAPR. The EPA subsequently clarified that compliance with the CSAPR would begin in 2015 using the amount of allowances originally scheduled to be available in 2012. As of December 31, 2015, OG&E has installed five low NO_X burner systems on two Muskogee units, two Sooner units and one Seminole unit and is in compliance with the final rule. In the meantime, the petitions for review of the supplemental rule remain pending before the D.C. Circuit Court of Appeals for consideration of issues that are not addressed by the Supreme Court's decision.

On December 3, 2015, the EPA proposed an update to CSAPR finding that ozone-season NO_X emissions in23eastern states including Oklahoma affect the ability of downwind states to attain and maintain ozone standards and proposing to issue FIPs to update the existing NO_X ozone-season emission budgets for electrical generating units. The proposed rule reduces OG&E's NO_X emissions requirements under the current CSAPR by 25 percent. Compliance is proposed to begin in May 2017. OG&E continues to evaluate what additional measures, if any, will be needed for compliance with the new rule.

Hazardous Air Pollutants Emission Standards

On February 16, 2012, the EPA published the final MATS rule regulating the emissions of certain hazardous air pollutants from electric generating units, which became effective April 16, 2012. The final rule uses a numerical standard to establish limits for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. Compliance was required within three years of the rule's effective date. Based on OG&E's request for a one-year extension, the deadline for compliance was extended to April 16, 2016. To comply with this rule, OG&E utilized activated carbon injections at each of its five coal-fired units during 2015.

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The final MATS rule was appealed by several parties, but OG&E was not a party to the appeals.  After withstanding judicial scrutiny at the District of Columbia Circuit Court of Appeals, the MATS rule was challenged at the U.S. Supreme Court.  On June 29, 2015, the U.S. Supreme Court found that the EPA should have considered the compliance costs imposed on utilities at the first stage of the EPA’s regulatory analysis.  The U.S. Supreme Court did not vacate the rule, but reversed the D.C. Circuit's decision and remanded to the D.C. Circuit for further proceedings. The Company believes that it is in compliance with the existing MATS rule.

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, on behalf of the EPA, 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 sought 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. The Sierra Club did not seek review of the case by the United States Supreme Court. OG&E considers this case now closed.

National Ambient Air Quality Standards

The EPA is required to set NAAQS for certain pollutants considered to be harmful to public health or the environment. The Clean Air Act requires the EPA to review each NAAQS every five years. As a result of these reviews, the EPA periodically has taken action to adopt more stringent NAAQS for those pollutants. If any areas of Oklahoma were to be designated as not attaining the NAAQS for a particular pollutant, the Company could be required to install additional emission controls on its facilities to help the state achieve attainment with the NAAQS. As of June 30, 2016, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect the Company's operations. Several processes are under way to designate areas in Oklahoma as attaining or not attaining revised NAAQS. The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.

In August of 2013, the Sierra Club and the Natural Resources Defense Council filed a complaint under the citizen suit provision of the Clean Air Act based on the EPA's failure to promulgate and publish designations for the 2010 revised primary SO₂ NAAQS. On March 2, 2015, the U.S. District Court for the Northern District of California issued an order granting the EPA and the Sierra Club's joint motion to approve and enter a consent decree that set forth mandatory deadlines for the EPA to issue designations for all areas of the country that remained undesignated. On September 18, 2015 the ODEQ reported to the EPA that no areas in Oklahoma should be designated as non-attainment for the 2010 SO₂ standard.  In a letter dated February 11, 2016, EPA Region 6 notified Oklahoma of their intent to designate part of Muskogee County in which OG&E’s Muskogee Power Plant is located, as non-attainment for the 2010 SO₂ NAAQS. This new designation was required to be finalized according to the EPA-Sierra Club consent decree by July 2, 2016. On June 17, 2016, the EPA and the Sierra Club entered into a joint agreement to extend the July 2, 2016 deadline by 60 days for certain areas including the Muskogee area. The new date for a final EPA decision

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on the proposed designation for the Muskogee area will be August 31, 2016. The EPA published final decisions on all other areas not subject to the extension on July 12, 2016. In this decision, Noble County, in which the Sooner plant is located, was deemed to be in attainment with the 2010 standard. On August 21, 2015, the EPA finalized a data requirements rule for implementing the 2010 SO₂ standard requiring air agencies to characterize air quality around sources that emit 2,000 tons per year or more of SO₂ via air quality modeling or ambient air monitoring.  On June 28, 2016, the ODEQ filed their emissions monitoring plan with the EPA in compliance with the rule, stating that ambient monitoring will be used as the method for characterizing air quality for sources which release 2,000 tons of SO₂ per year or more.  At this time, OG&E cannot determine with any certainty whether this determination will cause a material impact to the Company's financial results.

On September 30, 2015 the EPA finalized a new ambient standard for ozone at 70 Ppb which is more stringent than the current standard of 75 Ppb, set in 2008. States must submit non-attainment designations as appropriate based on existing ambient data before October 2016 for the EPA’s approval. Compliance with the new standard begins in 2020 or later depending on the degree of the area’s non-attainment designation. All areas in Oklahoma currently meet the new standard.

The Company is monitoring those processes and their possible impact on its operations but, at this time, cannot determine with any certainty whether they will cause a material impact to the Company's financial results.

Clean Power Plan

On October 23, 2015, the EPA published the final Clean Power Plan that established standards of performance for CO₂ emissions from existing fossil-fuel-fired power plants along with state-specific CO₂ reduction standards expressed as both rate-based (lbs/MWh) and mass-based (tons/yr) goals. The 2030 rate-based reduction requirement for all existing generating units in Oklahoma has decreased from a proposed43 percentreduction to32 percentin the final rule.  The mass-based approach for existing units calls for a24 percentreduction by 2030 in Oklahoma. The Clean Power Plan requires that states submit to the EPA plans for achieving the state-specific CO₂ reduction goals by September 6, 2016 or submit an extension request for up to two years. The compliance period was to begin in 2022, and emission reductions were to be phased in by 2030. The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan was not submitted to the EPA by the required deadline.

A number of states have filed lawsuits against the Clean Power Plan. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan pending resolution of challenges to the rule. The Company is unable to determine what impact the lawsuits will ultimately have on the Clean Power Plan or what impact the stay in implementation will have; however, if the Clean Power Plan survives judicial review and is implemented as written, it could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations and cash flows if such costs are not recovered through regulated rates. Significant uncertainties would remain with regards to potential implementation in Oklahoma (and the federal plan that would be imposed by the EPA for states that do not submit approvable plans), including whether states would elect an emissions standards approach versus a state measures approach, whether and what type of emissions trading would be allowed, and available cost mitigation options. Due to the pending litigation and the uncertainties in the state approaches, the ultimate timing and impact of these standards on our operations cannot be determined with certainty at this time.

Climate Change and Greenhouse Gas Emissions

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including CO₂, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the earth's atmosphere.  In December 2015, as part of the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change, the United States committed to reduce economy wide emissions by 26 percent to 28 percent below 2005 emission levels. This multinational agreement became open for signing on April 22, 2016 and will require countries to review and "represent a progression" every five years beginning in 2020. The agreement could result in future additional emissions reductions in the United States, however, it is not possible to determine what the international legal standards for greenhouse gas emissions will be in the future and the extent to which commitments under the December 2015 Paris Agreement will be implemented through the Clean Air Act, other than existing statutes and new legislation.

Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.

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If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of CO₂ and other greenhouse gases on the Company's facilities, this could result in significant additional compliance costs that would affect the Company’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

In 2009, the EPA adopted a comprehensive national system for reporting emissions of CO₂ and other greenhouse gases produced by major sources in the United States. The reporting requirements apply to large direct emitters of greenhouse gases with emissions equal to or greater than a threshold of 25,000 metric tons per year, which includes certain OG&E facilities. OG&E also reports quarterly its CO₂ emissions from generating units subject to the Federal Acid Rain Program. OG&E has submitted the reports required by the applicable reporting rules.

Nonetheless, OG&E’s current business strategy will result in a reduced carbon emissions rate compared to current levels. As discussed in “Pending Regulatory Matters”, OG&E has filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP by converting two coal-fired generating units at Muskogee Station to natural gas, among other measures. OG&E’s deployment of Smart Grid technology helps to reduce the peak load demand. OG&E also seeks to utilize renewable energy sources that do not emit greenhouse gases. OG&E's service territory borders one of the nation's best wind resource areas. OG&E has leveraged its geographic position to develop renewable energy resources and completed transmission investments to deliver the renewable energy. The SPP has begun to authorize the construction of transmission lines capable of bringing renewable energy out of the wind resource area in western Oklahoma, the Texas Panhandle and western Kansas to load centers by planning for more transmission to be built in the area. In addition to increasing overall system reliability, these new transmission resources should provide greater access to additional wind resources that are currently constrained due to existing transmission delivery limitations.

EPA Startup, Shutdown, and Malfunction Policy

On May 22, 2015, the EPA issued a final rule to address the outdated provisions in the SIP of 36 states, including Oklahoma, regarding the treatment of emissions that occur during startup, shutdown and malfunction operations. The final rule clarifies the EPA's Startup, Shutdown and Malfunction Policy to assure consistency with the Clean Air Act and other recent court decisions. The Oklahoma Department of Environmental Quality is in the process of developing a SIP to comply with this rule, which is to be submitted to the EPA before November 2016. Although the extent of impact is not known, this rule will impact certain OG&E units.

Endangered Species

Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats.  If such species are located in an area in which the Company conducts operations, or if additional species in those areas become subject to protection, the Company’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company could be required to implement expensive mitigation measures.

In 2014, the Company enrolled in the Western Association of Fish and Wildlife Agencies range-wide conservation plan which consists of industry-specific conservation practices that apply to projects and activities in the impacted area. The range-wide conservation plan was approved by the U.S. Fish and Wildlife Service and incorporated as part of the agency’s final decision on March 27, 2014 to list the lesser prairie chicken as a threatened species. On September 1, 2015, the U.S. District Court Western District of Texas vacated federal protections for the lesser prairie chicken based on the U.S. Fish and Wildlife Service's failure to thoroughly consider the active conservation efforts in making the listing decision. On July 19, 2016, the U.S. Fish and Wildlife Service issued a final rule to amend its regulations to remove the lesser prairie chicken from the list of threatened species under the Endangered Species Act.

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 “Pending Regulatory Matters” in Note 13 to Notes to Condensed Consolidated Financial Statements of Part I, Item I of this Form 10-Q.

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Waste

OG&E's operations generate wastes that are subject to the Federal Resource Conservation and Recovery Act of 1976 as well as comparable state laws which impose detailed requirements for the handling, storage, treatment and disposal of waste.

On December 19, 2014, the EPA finalized a rule under the Federal Resource Conservation and Recovery Act for the handling and disposal of coal combustion residuals or coal ash. The final rule regulates coal ash as a solid waste rather than a hazardous waste, which would have made the management of coal ash more costly. The final rule is currently being appealed at the D.C. Circuit Court of Appeals. OG&E is in compliance with this rule at this time.

The Company has sought and will continue to seek pollution prevention opportunities and to evaluate the effectiveness of its waste reduction, reuse and recycling efforts.  In 2015, the Company obtained refunds of $2.3 million from the recycling of scrap metal, salvaged transformers and used transformer oil.  This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials.  Similar savings are anticipated in future years.

Water

OG&E's operations are subject to the Federal Clean Water Act and comparable state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters.

The EPA issued a final rule on May 19, 2014 to implement Section 316(b) of the Federal Clean Water Act, which requires that power plant cooling water intake structure location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. OG&E submitted compliance plans to the state in April 2015. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the state.

On September 30, 2015, the EPA issued a final rule addressing the effluent limitation guidelines for power plants under the Federal Clean Water Act. The final rule establishes technology and performance based standards that may apply to discharges of six waste streams including bottom ash transport water. Compliance with this rule occurs between 2018 and 2023. OG&E is evaluating what if any compliance actions are needed but is not able to quantify with any certainty, what costs may be incurred. OG&E expects to be able to provide a reasonable estimate of any material costs associated with the rule's implementation following issuance of the permits from the state.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regard to the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Because OG&E utilizes various products and generate wastes that are considered hazardous substances for purposes of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, OG&E could be subject to liability for the costs of cleaning up and restoring sites where those substances have been released to the environment.  At this time, it is not anticipated that any associated liability will cause a significant impact to OG&E.

For a further discussion regarding contingencies relating to environmental laws and regulations, see Note 12 of Notes to Condensed Consolidated Financial Statements of Part I, Item 1 of this Form 10-Q.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

There have been no significant changes in the market risks affecting the Company from those discussed in the Company's 2015 Form 10-K.

Item 4.  Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer, allowing timely decisions regarding required disclosure.As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with

46

the participation of the Company's management, including the chief executive officer and chief financial officer, of the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that the Company's disclosure controls and procedures are effective.

No change in the Company's internal control over financial reporting has occurred during the Company's most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2015Form 10-K for a description of certain legal proceedings presently pending. Except as described above under Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Laws and Regulations," there are no new significant cases to report against the Company or its subsidiaries and there have been no material changes in the previously reported proceedings.

Item 1A.  Risk Factors.

Except as discussed below, there have been no significant changes in the Company's risk factors from those discussed in the Company's 2015Form 10-K, which are incorporated herein by reference.

Enable's Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.

Enable's 10 percent Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable (Enable's “Series A Preferred Units”), issued in February 2016, rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. Enable cannot declare or pay a distribution to its common or subordinated unitholders for any quarter unless full distributions have been or contemporaneously are being paid on all outstanding Series A Preferred Units for such quarter. These preferences could adversely affect the cash distributions we receive from Enable, or could make it more difficult for Enable to sell its common units in the future.

Holders of the Series A Preferred Units will receive, on a non-cumulative basis and if and when declared by Enable's general partner, a quarterly cash distribution, subject to certain adjustments, equal to an annual rate of 10 percent on the stated liquidation preference from the date of original issue to, but not including, the five year anniversary of the original issue date, and an annual rate of the London Interbank Offered Rate plus a spread of 850 basis points on the stated liquidation preference thereafter. In connection with certain transfers of the Series A Preferred Units, the Series A Preferred Units will automatically convert into one or more new series of preferred units (the “other preferred units”) on the later of the date of transfer or the second anniversary of the date of issue. The other preferred units will have the same terms as Enable's Series A Preferred Units except that unpaid distributions on the other preferred units will accrue from the date of their issuance on a cumulative basis until paid. Enable's Series A Preferred Units are convertible into common units by the holders of such units in certain circumstances. Payment of distributions on Enable's Series A Preferred Units, or on the common units issued following the conversion of such Series A Preferred Units, could impact its liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Enable's obligations to the holders of Series A Preferred Units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.

Enable's Series A Preferred Units contain covenants that may limit its business flexibility.

Enable's Series A Preferred Units contain covenants preventing it from taking certain actions without the approval of the holders of 66 2⁄3 percent of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede Enable's ability to take certain actions that management or its board of directors may consider to be in the best interests of its unitholders. The affirmative vote of 66 2⁄3 percent of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend Enable's Partnership Agreement in any manner that would or could reasonably be expected to have a material adverse effect on the rights, preferences, obligations or privileges of the Series A Preferred Units. The affirmative vote of 66 2⁄3 percent of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) create or issue certain party securities with proceeds in an aggregate amount in excess of $700.0 million or create or issue any senior securities or (B) subject to Enable's right to redeem the Series A Preferred Units, approve certain fundamental transactions.

Enable's Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange, and Enable may not have sufficient funds to redeem its Series A Preferred Units if it is required to do so.

The holders of Enable's Series A Preferred Units may request that Enable list those units for trading on the New York Stock Exchange. If Enable is unable to list the Series A Preferred Units in certain circumstances, it will be required to redeem the Series A Preferred Units. There can be no assurance that Enable would have sufficient financial resources available to satisfy its

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obligation to redeem the Series A Preferred Units. In addition, mandatory redemption of Enable's Series A Preferred Units could have a material adverse effect on its business, financial position, results of operations and ability to make quarterly cash distributions to its unitholders.

Our operating cash flow is derived partially from cash distributions we receive from Enable.

Our operating cash flow is derived partially from cash distributions we receive from Enable. The amount of cash Enable can distribute on its units principally depends upon the amount of cash generated from its operations, which will fluctuate from quarter to quarter based on, among other things:

• the fees and gross margins it realizes with respect to the volume of natural gas, NGLs and crude oil that it handles;

• the prices of, levels of production of, and demand for natural gas, NGLs and crude oil;

• the volume of natural gas, NGLs and crude oil it gathers, compresses, treats, dehydrates, processes, fractionates, transports and stores;

• the relationship among prices for natural gas, NGLs and crude oil;

• cash calls and settlements of hedging positions;

• margin requirements on open price risk management assets and liabilities;

• the level of competition from other midstream energy companies;

• adverse effects of governmental and environmental regulation;

• the level of its operation and maintenance expenses and general and administrative costs; and

• prevailing economic conditions.

In addition, the actual amount of cash Enable will have available for distribution will depend on other factors, including:

• the level and timing of capital expenditures it makes;

• the cost of acquisitions;

• its debt service requirements and other liabilities;

• fluctuations in working capital needs;

• its ability to borrow funds and access capital markets;

• restrictions contained in its debt agreements;

• the amount of cash reserves established by its general partner

• distributions paid on its Series A Preferred Units; and

• other business risks affecting its cash levels.

The amount of cash Enable has available for distribution to its limited partners depends primarily on its cash flow rather than on its profitability, which may prevent Enable from making distributions, even during periods in which it records net income.

The amount of cash Enable has available for distribution depends primarily upon its cash flows and not solely on profitability, which will be affected by non-cash items. As a result, Enable may make cash distributions during periods when it records losses for financial accounting purposes and may not make cash distributions during periods when it records net earnings for financial accounting purposes.

Enable is expected to pay a specified minimum quarterly distribution on its outstanding common and subordinated units, including those units that we own, to the extent it has sufficient cash from operations after establishment of cash reserves, payments of distributions on the Series A Preferred Units and payment of fees and expenses, including payments to its general partner and its affiliates. The principal difference between Enable’s common units and subordinated units is that in any quarter during the applicable subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on common units from prior quarters. If Enable does not pay distributions on its subordinated units, its subordinated units will not accrue arrearages for those unpaid distributions.

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Enable may issue additional units without the approval of its unitholders, which would dilute unitholders' existing ownership interests.

Enable's partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that it may issue at any time without the approval of its unitholders. The issuance by Enable of additional common units or other equity securities of equal or senior rank will have the following effects:

• Enable's existing unitholders’ proportionate ownership interest in Enable will decrease;

• the amount of distributable cash flow on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by Enable's common unitholders will increase;

• because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

In addition, upon a change of control, Enable's Series A Preferred Units are convertible into common units at the option of the holders of such units. If a substantial portion of the Series A Preferred Units were converted into common units, common unitholders could experience significant dilution. In addition, if holders of such converted Series A Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for Enable's common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for Enable to sell its common units in the future.

Affiliates of Enable's general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units.

As of July 2016, subsidiaries of CenterPoint Energy and the Company hold an aggregate of 136,983,998 common units and 207,855,430 subordinated units, and CenterPoint Energy holds 14,520,000 Series A Preferred Units. Upon a change of control, Enable's Series A Preferred Units are convertible into common units at the option of the holders of such units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier under certain circumstances. In addition, Enable has agreed to provide CenterPoint Energy, the Company and ArcLight with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

The following table contains information about the Company's purchases of its common stock during the second quarter of 2016.

Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
04/01/16 - 04/30/16	—		$	—	N/A	N/A
05/01/16 - 05/31/16	173	(A)	$	30.81	N/A	N/A
06/01/16 - 06/30/16	—		$	—	N/A	N/A

(A) These shares of restricted stock were returned to the Company to satisfy tax liabilities.

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Item 6.  Exhibits.

Exhibit No.	Description
10.01	Fourth Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated June 22, 2016 (Filed as Exhibit 10.01 to the Company's Form 8-K filed June 22, 2016 (File No. 1-12579) and incorporated by reference herein)
10.02	Third Amended and Restated Limited Liability Company Agreement of Enable GP, LLC, dated June 22, 2016 (Filed as Exhibit 10.02 to the Company's Form 8-K filed June 22, 2016 (File No. 1-12579) and incorporated by reference herein)
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Press release dated June 29, 2016 announcing OG&E's implementation of interim rates and reduced fuel costs (Filed as Exhibit 99.01 to the Company's Form 8-K filed June 29, 2016 (File No. 1-12579) and incorporated by reference herein)
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.PRE	XBRL Taxonomy Presentation Linkbase Document.
101.LAB	XBRL Taxonomy Label Linkbase Document.
101.CAL	XBRL Taxonomy Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	OGE ENERGY CORP.
	(Registrant)
By:	/s/ Scott Forbes
	Scott Forbes
	Controller and Chief Accounting Officer
	(On behalf of the Registrant and in his capacity as Chief Accounting Officer)

August 4, 2016

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EX-31.01

Exhibit 31.01

CERTIFICATIONS

I, Sean Trauschke, certify that:

1. I have reviewed this quarterly report on Form 10-Q ofOGE Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 4, 2016

  /s/ Sean Trauschke

Sean Trauschke

President and Chief Executive Officer

Exhibit 31.01

CERTIFICATIONS

I, Stephen Merrill, certify that:

1. I have reviewed this quarterly report on Form 10-Q ofOGE Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 4, 2016

  /s/ Stephen Merrill

Stephen Merrill

Chief Financial Officer

EX-32.01

Exhibit 32.01

Certification Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of the Company on Form 10-Q for the period endedJune 30, 2016, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 4, 2016

          /s/ Sean Trauschke

               Sean Trauschke

President and Chief Executive Officer

          /s/ Stephen Merrill

               Stephen Merrill

Chief Financial Officer

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Document and Entity Information Document	6 Months Ended
	Jun. 30, 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	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	199,702,025

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OPERATING REVENUES	$ 551.4	$ 549.9	$ 984.5	$ 1,030.0
COST OF SALES	197.7	210.9	375.6	422.5
OPERATING EXPENSES
Other operation and maintenance	127.6	113.2	241.5	224.9
Depreciation and amortization	80.1	76.2	158.6	152.1
Taxes other than income	20.1	22.4	45.0	46.9
Total operating expenses	227.8	211.8	445.1	423.9
OPERATING INCOME	125.9	127.2	163.8	183.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	16.7	28.2	45.0	59.9
Allowance for equity funds used during construction	3.7	1.7	5.3	3.2
Other income	7.6	5.6	13.2	10.5
Other expense	(5.8)	(2.2)	(7.5)	(3.2)
Net other income	22.2	33.3	56.0	70.4
INTEREST EXPENSE
Interest on long-term debt	35.7	37.0	71.5	73.9
Allowance for borrowed funds used during construction	(1.8)	(0.8)	(2.7)	(1.6)
Interest on short-term debt and other interest charges	2.1	1.8	3.5	3.1
Interest expense	36.0	38.0	72.3	75.4
INCOME BEFORE TAXES	112.1	122.5	147.5	178.6
INCOME TAX EXPENSE	40.6	35.0	50.8	47.9
NET INCOME	$ 71.5	$ 87.5	$ 96.7	$ 130.7
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7	199.6	199.7	199.6
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.8	199.6	199.8	199.6
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.35	$ 0.44	$ 0.48	$ 0.66
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.35	0.44	0.48	0.66
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.27500	$ 0.25000	$ 0.55000	$ 0.50000

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net income	$ 71.5	$ 87.5	$ 96.7	$ 130.7
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4, $0.6, $0.8 and $1.4, respectively	0.7	0.8	1.5	1.2
Settlement cost, net of tax of $3.2, $0, $3.2 and $0, respectively	5.0	0.0	5.0	0.0
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0, $0.2, $0 and $0.4, respectively	0.0	0.4	0.0	0.6
Amortization of prior service cost, net of tax of ($0.3), ($0.2), ($0.5) and ($0.5), respectively	(0.4)	(0.5)	(0.8)	(0.9)
Other comprehensive income, net of tax	5.3	0.7	5.7	0.9
Comprehensive income	$ 76.8	$ 88.2	$ 102.4	$ 131.6

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.4	$ 0.6	$ 0.8	$ 1.4
Settlement cost	3.2	0.0	3.2	0.0
Postretirement Benefit Plans:
Amortization of deferred net loss	0.0	0.2	0.0	0.4
Amortization of prior service cost	(0.3)	(0.2)	(0.5)	(0.5)
Amortization of deferred interest rate swap hedging losses	$ 0.0	$ 0.0	$ 0.0	$ 0.0

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 96.7	$ 130.7
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	158.6	152.1
Deferred income taxes and investment tax credits	52.2	48.1
Equity in earnings of unconsolidated affiliates	(45.0)	(59.9)
Distributions from unconsolidated affiliates	45.4	68.9
Allowance for equity funds used during construction	(5.3)	(3.2)
Stock-based compensation	3.2	2.4
Regulatory assets	(4.0)	2.5
Regulatory liabilities	(8.4)	(2.0)
Other assets	6.8	4.5
Other liabilities	5.7	(2.4)
Change in certain current assets and liabilities
Accounts receivable, net	10.0	2.9
Accounts receivable - unconsolidated affiliates	3.1	3.2
Accrued unbilled revenues	(37.4)	(30.8)
Fuel, materials and supplies inventories	11.2	(29.7)
Fuel clause under recoveries	0.0	64.6
Other current assets	(17.7)	(10.2)
Accounts payable	(56.8)	(40.7)
Fuel clause over recoveries	(20.0)	1.6
Other current liabilities	(32.3)	3.2
Net Cash Provided from Operating Activities	166.0	305.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(331.1)	(227.7)
Return of capital - equity method investments	25.2	0.0
Proceeds from sale of assets	0.2	2.0
Net Cash Used in Investing Activities	(305.7)	(225.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(109.8)	(99.8)
Issuance of common stock	0.0	6.8
Payment of long-term debt	(110.1)	(0.1)
Increase in short-term debt	284.4	7.5
Net Cash Provided from (Used in) Financing Activities	64.5	(85.6)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(75.2)	(5.5)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	75.2	5.5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0.0	$ 0.0

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 0.0	$ 75.2
Accounts receivable, less reserve of $1.5 and $1.4, respectively	163.1	173.1
Accounts receivable - unconsolidated affiliates	0.0	1.7
Accrued unbilled revenues	90.9	53.5
Income taxes receivable	14.6	17.2
Fuel inventories	107.1	113.8
Materials and supplies, at average cost	75.6	80.1
Other	75.9	55.6
Total current assets	527.2	570.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,168.8	1,194.4
Other	72.4	70.7
Total other property and investments	1,241.2	1,265.1
PROPERTY, PLANT AND EQUIPMENT
In service	10,522.7	10,318.3
Construction work in progress	319.4	278.5
Total property, plant and equipment	10,842.1	10,596.8
Less accumulated depreciation	3,372.2	3,274.4
Net property, plant and equipment	7,469.9	7,322.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	401.9	402.2
Other	19.0	20.7
Total deferred charges and other assets	420.9	422.9
TOTAL ASSETS	9,659.2	9,580.6
CURRENT LIABILITIES
Short-term debt	284.4	0.0
Accounts payable - unconsolidated affiliates	1.4	0.0
Accounts payable	159.7	262.5
Dividends payable	54.9	54.9
Customer deposits	77.5	77.0
Accrued taxes	39.4	45.9
Accrued interest	40.3	42.9
Accrued compensation	35.7	54.4
Long-term debt due within one year	0.0	110.0
Fuel clause over recoveries	41.3	61.3
Other	38.9	43.9
Total current liabilities	773.5	752.8
LONG-TERM DEBT	2,629.7	2,628.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	300.1	299.9
Deferred income taxes	2,232.6	2,178.2
Regulatory liabilities	283.9	273.6
Other	117.6	121.3
Total deferred credits and other liabilities	2,934.2	2,873.0
Total liabilities	6,337.4	6,254.6
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,104.5	1,101.3
Retained earnings	2,246.7	2,259.8
Accumulated other comprehensive loss, net of tax	(29.4)	(35.1)
Total stockholders' equity	3,321.8	3,326.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 9,659.2	$ 9,580.6

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Allowance for Doubtful Accounts Receivable	$ 1.4	$ 1.6

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CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Unaudited) - USD ($) $ in Millions	Total	Common Stock	Premium on Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
Balance at Dec. 31, 2014	$ 3,244.4	$ 2.0	$ 1,085.6	$ 2,198.2	$ (41.4)
Changes in Stockholders' Equity
Net income	130.7	0.0	0.0	130.7	0.0
Other comprehensive income, net of tax	0.9	0.0	0.0	0.0	0.9
Dividends declared on common stock	(99.8)	0.0	0.0	(99.8)	0.0
Issuance of common stock	6.8	0.0	6.8	0.0	0.0
Stock-based compensation	3.0	0.0	3.0	0.0	0.0
Balance at Jun. 30, 2015	3,286.0	2.0	1,095.4	2,229.1	(40.5)
Balance at Dec. 31, 2015	3,326.0	2.0	1,099.3	2,259.8	(35.1)
Changes in Stockholders' Equity
Net income	96.7	0.0	0.0	96.7	0.0
Other comprehensive income, net of tax	5.7	0.0	0.0	0.0	5.7
Dividends declared on common stock	(109.8)	0.0	0.0	(109.8)	0.0
Stock-based compensation	3.2	0.0	3.2	0.0	0.0
Balance at Jun. 30, 2016	$ 3,321.8	$ 2.0	$ 1,102.5	$ 2,246.7	$ (29.4)

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 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 segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operationsare conducted through OG&E andare subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company.OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

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

Enable was formed effective May 1, 2013by 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 andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable.The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by 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 atJune 30, 2016andDecember 31, 2015, the results of its operations for the three and six months endedJune 30, 2016and2015 and its cash flows for thesix months endedJune 30, 2016and2015, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company'soperating results for thethree and six months endedJune 30, 2016are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2016or 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 2015Form 10-K.

Schedule of Regulatory Assets and Liabilities

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC.  Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain incurred costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates.  Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates.  Management's expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

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

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

	June 30,		December 31,
(In millions)	2016		2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	43.9	$	36.6
SPP cost tracker rider under recovery (A)	7.5		4.5
Other (A)	11.8		5.4
Total Current Regulatory Assets	$	63.2	$	46.5
Non-Current
Benefit obligations regulatory asset	$	237.3	$	242.2
Income taxes recoverable from customers, net	58.3		56.7
Smart Grid	43.5		43.6
Deferred storm expenses	31.8		27.6
Unamortized loss on reacquired debt	14.1		14.8
Other	16.9		17.3
Total Non-Current Regulatory Assets	$	401.9	$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	41.3	$	61.3
Other (B)	4.5		7.5
Total Current Regulatory Liabilities	$	45.8	$	68.8
Non-Current
Accrued removal obligations, net	$	256.2	$	254.9
Pension tracker	26.7		17.7
Other (C)	1.0		1.0
Total Non-Current Regulatory Liabilities	$	283.9	$	273.6

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

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

(C) Prior year amount of$1.0 millionreclassified 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 thesix months endedJune 30, 2016and2015.

	Six Months Ended June 30,
(In millions)	2016		2015
Balance at January 1	$	63.3	$	58.6
Accretion expense	1.4		1.3
Liabilities settled	—		(0.5		)
Balance at June 30	$	64.7	$	59.4

Comprehensive Income (Loss) Note [Text Block]

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months endedJune 30, 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 income		Prior service cost			Total
Balance at December 31, 2015	$	(39.2	)	$	0.1	$	2.5	$	1.5		$	(35.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.5			—		—		(0.8		)	0.7
Settlement cost	5.0			—		—		—			5.0
Net current period other comprehensive income (loss)	6.5			—		—		(0.8		)	5.7
Balance at June 30, 2016	$	(32.7	)	$	0.1	$	2.5	$	0.7		$	(29.4	)

	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)	1.2			—		0.6			(0.9		)	0.9
Balance at June 30, 2015	$	(35.6	)	$	0.1	$	(7.4	)	$	2.4		$	(40.5	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and six months endedJune 30, 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						Six Months Ended
	June 30,						June 30,
(In millions)	2016			2015			2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.1	)	$	(1.4	)	$	(2.3	)	$	(2.6	)	(A)
Settlement	(8.2		)	—			(8.2		)	—			(A)
	(9.3		)	(1.4		)	(10.5		)	(2.6		)	Total before tax
	(3.6		)	(0.6		)	(4.0		)	(1.4		)	Tax benefit
	$	(5.7	)	$	(0.8	)	$	(6.5	)	$	(1.2	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.6	)	$	—		$	(1.0	)	(A)
Prior service credit	0.7			0.7			1.3			1.4			(A)
	0.7			0.1			1.3			0.4			Total before tax
	0.3			—			0.5			0.1			Tax expense
	$	0.4		$	0.1		$	0.8		$	0.3		Net of tax
Total reclassifications for the period	$	(5.3	)	$	(0.7	)	$	(5.7	)	$	(0.9	)	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

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

TheDecember 31, 2015Balance Sheethas been adjusted for the reclassification of$16.8 millionof debt issuance costs from total deferred charges and other assets to long-term debt to be consistent with the2016presentation due to the adoption of ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," in2016.

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Accounting Pronouncements

6 Months Ended

Jun. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

Accounting Pronouncements

Revenue from Contracts with Customers.In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". The new 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 ASU 2016-09. Under the new guidance, the windfall tax benefit will be recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the current requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. Either prospective or retrospective transition of this provision is permitted.ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016, and interim periods within that reporting period. 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.

Financial Instruments-Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses: Measurement of Credit Losses on Financial Instruments.” The amendment in this update requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely matter. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Company does not believe this ASU will have any effect on its Condensed Consolidated Financial Statements.

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Investment in Unconsolidated Affiliates

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Investment in Unconsolidated Affiliate

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. The Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2016. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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

Investment in Unconsolidated Affiliate and Related Party Transactions

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

Pursuant to the Master Formation Agreement, the Company and the ArcLight group indirectly contributed100 percentof the equity interests inEnogex LLCto 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 June 30, 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 $34.6 million during the three months endedJune 30, 2016 and 2015, respectively, and $70.6 million and $68.9 million for the six months endedJune 30, 2016 and 2015, respectively. On August 3, 2016, Enable announced a quarterly dividend distribution of$0.3180per unit on its outstanding common and subordinated units, representing the same dividend distribution as the previous quarter.

CenterPoint had previously announced that it was evaluating strategic alternatives for its investment in Enable.  On July 18, 2016, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided notice to the Company of CenterPoint’s solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. This notice also constituted a notice pursuant to the right of first offer held by the Company under the Partnership Agreement and the Third Amended and Restated Limited Liability Company Agreement of the general partner.  Under the terms of the right of first offer, the Company has 30 days from receipt of the notice from CenterPoint to make an offer to buy all of CenterPoint’s membership interests in the general partner and all or any portion of CenterPoint Energy Resources Corp. common units and subordinated units.  If the Company were to make an offer under the right of first offer, then CenterPoint would have 30 days to accept such offer.  The Company is currently evaluating its options with respect to the right of first offer.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, are discussed below.

On May 1, 2013, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2016. Under these agreements, the Company charged operating costs to Enable of $1.3 million and $2.5 million for the three months endedJune 30, 2016 and 2015, respectively, and $2.6 million and $5.3 million for the six months endedJune 30, 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/or Enable are assigned as such.  Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

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 of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $7.0 million and $8.1 million during the three months endedJune 30, 2016 and June 30, 2015, respectively, and $14.1 million and $18.1 million during the six months endedJune 30, 2016 and June 30, 2015, respectively, under the Transitional Seconding Agreement for employment costs.

The Company had accounts receivable from Enable of $2.8 million and $3.4 million as of June 30, 2016 and December 31, 2015, respectively, for amounts billed for transitional services, including the cost of seconded employees. Fuel purchases from Enable are excluded.

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 thethree and six months endedJune 30, 2016 and 2015.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Operating Revenues:
Electricity to power electric compression assets	$	3.0	$	3.6	$	5.3	$	6.7
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.7	$	17.5	$	17.5
Natural gas purchases/(sales)	5.4		2.1		6.9		4.6

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2016 and December 31, 2015 and for the three and six months endedJune 30, 2016 and 2015.

	June 30,		December 31,
Balance Sheet	2016		2015
(In millions)
Current assets	$	349	$	381
Non-current assets	10,851		10,845
Current liabilities	301		615
Non-current liabilities	3,150		3,080

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Income Statement	2016		2015		2016		2015
(In millions)
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of natural gas and natural gas liquids	254		277		449		569
Operating income	57		93		160		197
Net income	35		77		121		168

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

The Company recorded equity in earnings of unconsolidated affiliates of $16.7 million and $45.0 million for the three and six months endedJune 30, 2016, respectively, and $28.2 million and $59.9 million for the three and six months endedJune 30, 2015, respectively. Equity in earnings of unconsolidated affiliates includes the Company'sshare of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in net assets of Enable. The basis difference is the result of the initial contribution of Enogex 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 percentinterest in SESH. 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$768.7 million as of June 30, 2016.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for thethree and six months endedJune 30, 2016 and 2015.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2016		2015		2016		2015
(In millions)
OGE's share of Enable net income	$	9.1	$	20.6	$	30.4	$	44.4
Amortization of basis difference	3.0		3.6		5.9		7.1
Elimination of Enogex Holdings fair value and other adjustments	4.6		4.0		8.7		8.4
Equity in earnings of unconsolidated affiliates	$	16.7	$	28.2	$	45.0	$	59.9

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Fair Value Measurements

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3).  Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The three levels defined in the fair value hierarchy are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability.  Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The Company had nofinancial instruments measured at fair value on a recurring basis atJune 30, 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 financial instruments at June 30, 2016 and December 31, 2015.

	June 30,				December 31,
	2016				2015
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
Senior Notes	$	2,384.7	$	2,812.5	$	2,493.9	$	2,754.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.9		10.3		10.0		9.2
OGE Energy Senior Notes	99.7		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 which fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2016

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

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

Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree and six months endedJune 30, 2016 and 2015related to the Company's performance units and restricted stock.

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015
Performance units
Total shareholder return	$	1.1	$	1.9	$	2.2	$	3.8
Earnings per share	0.4		0.6		1.0		1.1
Total performance units	1.5		2.5		3.2		4.9
Restricted stock	0.1		0.1		0.1		0.1
Total compensation expense	1.6		2.6		3.3		5.0
Less: Amount paid by unconsolidated affiliates	—		0.2		—		0.5
Net compensation expense	$	1.6	$	2.4	$	3.3	$	4.5
Income tax benefit	$	0.7	$	1.0	$	1.3	$	1.8

During thethree and six months endedJune 30, 2016, the Company issued an immaterial number of shares to satisfy restricted stock grants.

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Income Taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions.With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to2012or state and local tax examinations by tax authorities for years prior to2011.  Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss.  Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

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Common Equity

6 Months Ended

Jun. 30, 2016

Common Equity [Text Block]

Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months endedJune 30, 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 June 30, 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 June 30,				Six Months Ended June 30,
(In millions except per share data)	2016		2015		2016		2015
Net income	$	71.5	$	87.5	$	96.7	$	130.7
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.6		199.7		199.6
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.1		—		0.1		—
Diluted average common shares outstanding	199.8		199.6		199.8		199.6
Basic Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Diluted Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Long-Term Debt

6 Months Ended

Jun. 30, 2016

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

AtJune 30, 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%	-	0.45%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.45%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.45%	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, at100 percentof 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.

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Short-Term Debt and Credit Facilities

6 Months Ended

Jun. 30, 2016

Short-term Debt [Abstract]

Short-Term Debt and Credit Facilities

Short-Term Debt and CreditFacilities

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 ofJune 30, 2016, the Company had$284.4 millionof short-term debt as compared tono balance at December 31, 2015. The following table provides information regarding the Company's revolving credit agreement at June 30, 2016.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
(In millions)
OGE Energy (B)	$	750.0	$	284.4	0.76	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0		1.7		0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0	$	286.1	0.76	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2016.

(B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  

(C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.

(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

(E) As of June 30, 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 downgradecould 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 millionin short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.

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Retirement Plans and Postretirement Benefit Plans

6 Months Ended

Jun. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Retirement Plans and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the quarter ended June 30, 2016, the Company experienced a settlement of its Supplemental Executive Retirement Plan, and its non-qualified Restoration of Retirement Income Plan. As a result, the Company recorded pension settlement charges of $8.7 million during the six months endedJune 30, 2016. The pension settlement charge did not increase the Company’s total pension expense over time, as the charges were an acceleration of costs that otherwise would be recognized as pension expense in future periods.

The 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
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)			2016 (B)		2015 (B)		2016 (C)		2015 (C)
Service cost	$	3.5		$	3.4		$	7.9		$	7.9		$	0.1	$	0.2	$	0.2	$	0.6
Interest cost	6.1			6.6			12.7			13.0			0.1		0.1		0.2		0.3
Expected return on plan assets	(10.2		)	(11.7		)	(20.7		)	(23.5		)	—		—		—		—
Amortization of net loss	4.0			5.4			8.2			9.7			0.1		0.2		0.3		0.3
Amortization of unrecognized prior service cost (A)	—			0.1			—			0.2			—		0.1		—		0.1
Settlement	—			—			—			—			8.7		—		8.7		—
Total net periodic benefit cost	3.4			3.8			8.1			7.3			9.0		0.6		9.4		1.3
Less: Amount paid by unconsolidated affiliates	1.2			1.0			2.5			2.1			0.2		0.1		0.2		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	2.2		$	2.8		$	5.6		$	5.2		$	8.8	$	0.5	$	9.2	$	1.2

(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$11.0 millionand$3.3 millionof net periodic benefit cost recognizedduring thethree months endedJune 30, 2016and2015, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedJune 30, 2016and2015of$2.6 millionand$2.4 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thethree months endedJune 30, 2016 of $0.6 millionrelated tothe pension settlement charge of$8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thethree months endedJune 30, 2016 of $0.1 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$8.7 million.

(C) In addition to the$14.8 millionand$6.4 millionof net periodic benefit cost recognizedduring thesix months endedJune 30, 2016and2015, respectively, OG&E recognized the following:

• an increase in pension expense during thesix months endedJune 30, 2016and2015of$4.9 millionand$5.4 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thesix months endedJune 30, 2016 of $0.6 millionrelated tothe pension settlement charge of$8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thesix months endedJune 30, 2016 of $0.1 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$8.7 million.

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)
Service cost	$	0.1		$	0.3		$	0.4		$	0.8
Interest cost	2.4			2.5			4.7			5.1
Expected return on plan assets	(0.5		)	(0.6		)	(1.1		)	(1.2		)
Amortization of net loss	0.8			3.5			1.3			6.9
Amortization of unrecognized prior service cost (A)	(2.2		)	(4.2		)	(4.4		)	(8.3		)
Total net periodic benefit cost	0.6			1.5			0.9			3.3
Less: Amount paid by unconsolidated affiliates	—			0.3			0.1			0.6
Net periodic benefit cost (net of unconsolidated affiliates)	$	0.6		$	1.2		$	0.8		$	2.7

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

(B) In addition to the$0.6 millionand$1.2 millionof net periodic benefit cost recognizedduring thethree months endedJune 30, 2016and2015, respectively, OG&E recognized an increase in postretirement medical expense duringthethree months endedJune 30, 2016and2015of$2.0 millionand$1.5 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$0.8 millionand$2.7 millionof net periodic benefit cost recognizedduring thesix months endedJune 30, 2016and2015, respectively, OG&E recognized an increase in postretirement medical expense duringthesix months endedJune 30, 2016and2015of$4.0 millionand$2.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Capitalized portion of net periodic pension benefit cost	$	0.8	$	1.2	$	2.0	$	2.0
Capitalized portion of net periodic postretirement benefit cost	0.2		0.4		0.4		0.9

Pension Plan Funding

In July 2016, the Company contributed$20.0 millionto its Pension Plan. No additional contributions are expected in 2016.

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Report of Business Segments

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Report of Business Segments

Report of Business Segments

The Company reports its operations in two business segments: (i) the electric utility segment, which is engaged in the generation, transmission, distribution and sale of electric energy, and (ii) the natural gas midstream operations segment.

Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations.

The following tables summarize the results of the Company's business segments during the three and six months endedJune 30, 2016 and 2015.

Three Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	551.4	$	—		$	—		$	—		$	551.4
Cost of sales	197.7		—			—			—			197.7
Other operation and maintenance	124.8		7.8			(5.0		)	—			127.6
Depreciation and amortization	78.4		—			1.7			—			80.1
Taxes other than income	19.1		—			1.0			—			20.1
Operating income (loss)	131.4		(7.8		)	2.3			—			125.9
Equity in earnings of unconsolidated affiliates	—		16.7			—			—			16.7
Other income (expense)	7.0		—			(1.4		)	(0.1		)	5.5
Interest expense	35.0		—			1.1			(0.1		)	36.0
Income tax expense (benefit)	31.1		9.3			0.2			—			40.6
Net income (loss)	$	72.3	$	(0.4	)	$	(0.4	)	$	—		$	71.5
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2

Three Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	549.9	$	—		$	—		$	—		$	549.9
Cost of sales	210.9		—			—			—			210.9
Other operation and maintenance	115.6		0.2			(2.6		)	—			113.2
Depreciation and amortization	74.3		—			1.9			—			76.2
Taxes other than income	21.6		—			0.8			—			22.4
Operating income (loss)	127.5		(0.2		)	(0.1		)	—			127.2
Equity in earnings of unconsolidated affiliates	—		28.2			—			—			28.2
Other income (expense)	4.4		—			0.8			(0.1		)	5.1
Interest expense	37.3		—			0.8			(0.1		)	38.0
Income tax expense (benefit)	25.6		10.0			(0.6		)	—			35.0
Net income (loss)	$	69.0	$	18.0		$	0.5		$	—		$	87.5
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1

Six Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	984.5	$	—		$	—		$	—		$	984.5
Cost of sales	375.6		—			—			—			375.6
Other operation and maintenance	241.1		8.0			(7.6		)	—			241.5
Depreciation and amortization	155.1		—			3.5			—			158.6
Taxes other than income	42.7		—			2.3			—			45.0
Operating income (loss)	170.0		(8.0		)	1.8			—			163.8
Equity in earnings of unconsolidated affiliates	—		45.0			—			—			45.0
Other income (expense)	12.3		—			(1.1		)	(0.2		)	11.0
Interest expense	70.5		—			2.0			(0.2		)	72.3
Income tax expense (benefit)	33.4		19.4			(2.0		)	—			50.8
Net income (loss)	$	78.4	$	17.6		$	0.7		$	—		$	96.7
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2

Six Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.0	$	—		$	—		$	—		$	1,030.0
Cost of sales	422.5		—			—			—			422.5
Other operation and maintenance	229.9		1.0			(6.0		)	—			224.9
Depreciation and amortization	148.1		—			4.0			—			152.1
Taxes other than income	44.7		—			2.2			—			46.9
Operating income (loss)	184.8		(1.0		)	(0.2		)	—			183.6
Equity in earnings of unconsolidated affiliates	—		59.9			—			—			59.9
Other income (expense)	7.3		—			3.3			(0.1		)	10.5
Interest expense	74.1		—			1.4			(0.1		)	75.4
Income tax expense (benefit)	31.9		18.1			(2.1		)	—			47.9
Net income (loss)	$	86.1	$	40.8		$	3.8		$	—		$	130.7
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Long-term Purchase Commitment [Line Items]

Commitments and Contingencies Disclosure [Text Block]

Commitments and Contingencies

Except as set forth below, in Note13 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 Notes14and15 to the Company's Consolidated Financial Statements included in the Company's 2015Form 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 ofOG&Eare 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 itscondensedfinancial position or results of operations.The Companybelieves, 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, on behalf of the EPA, 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 sought 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. The Sierra Club did not seek review of the case by the United States Supreme Court. OG&E considers this case now closed.

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 “Pending Regulatory Matters” in Note 13.

Other

In the normal course of business,the Companyis 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 Companyhas incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements.At the present time, based on currently available information, the Company believes that any reasonably possible losses in excess of accrued amounts arising out of pending or threatened lawsuits or claims would not be quantitatively material to its financial statements and would not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows.

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Rate Matters and Regulation

6 Months Ended

Jun. 30, 2015

Regulated Operations [Abstract]

Rate Matters and Regulation

Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note15to the Company's Consolidated Financial Statements included in the Company's 2015Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

FERC Order No. 1000, Final Rule on Transmission Planning and Cost Allocation

On July 21, 2011, the FERC issued Order No. 1000, which revised the FERC's existing regulations governing the process for planning enhancements and expansions of the electric transmission grid along with the corresponding process for allocating the costs of such expansions. Order No. 1000 requires individual regions to determine whether a previously-approved project is subject to reevaluation and is therefore governed by the new rule.

Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariff and agreement provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities or to alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP's pre-Order No. 1000 tariff included a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build previous transmission projects in Oklahoma. On May 29, 2013, the Governor of Oklahoma signed House Bill 1932 into law which establishes a "right of first refusal" for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300kV that interconnect to those incumbent owners' existing facilities.

The SPP has submitted compliance filings implementing Order No. 1000's requirements. In response, the FERC issued an order on the SPP filings that required the SPP to remove certain "right of first refusal" language from the SPP Tariff and the SPP Membership Agreement. On December 15, 2014, OG&E filed an appeal in the Court challenging the FERC's order requiring the removal of the "right of first refusal" language from the SPP Membership Agreement.

On July 1, 2016, the Court upheld the FERC's decision requiring removal of the rights of first refusal for incumbent transmission providers from the SPP Membership Agreement. The Court determined that the FERC had reasonably found the rights of first refusal in the SPP Membership Agreement to be anticompetitive.

The Company does not believe the Court’s ruling will have any impact on existing transmission projects for which the Company has already received a notice to construct from the SPP.  The Company intends to actively participate in the SPP planning process for competitive transmission projects that we believe apply to transmission voltage levels projects greater than 300kV.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. On May 26, 2016, the OCC issued a final order, finding that for the calendar year 2014 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent.

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.

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 PUD Staff's review.

In March 2014, the PUD Staff began their review of the Demand Program costs, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the 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 millionannually) in accordance with the agreement that it believed had been reached with the PUD Staff.

In April 2015, the 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 PUD Staff recommends the OCC approve the PUD Staff's 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 millionfrom 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 that OG&E will recover$10.1 millionof lost revenues associated with 2013,$11.6 millionassociated with 2014 and$14.9 millionassociated with 2015. Through June 30, 2016, OG&E had collected from its customers approximately$15.2 million of the$36.6 millionof lost revenues for 2013, 2014 and 2015.

A hearing on the 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 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$21.4 millionof 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 Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also 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. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015, approximately seven months after OG&E filed its application, 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 Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On December 11, 2015, OG&E filed a motion requesting modification of the OCC order for the purposes of approving only the ECP. 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 did not seek approval of the costs of the dry scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates.On April 28, 2016, the OCC approved the dry scrubber project and OG&E is proceeding with the project. Two parties to the proceeding have appealed the OCC's decision to the Oklahoma Supreme Court.

OG&E anticipates the total cost of dry scrubbers will be $547.5 million. As of June 30, 2016, OG&E had incurred$116.8 millionof construction work in progress on the dry scrubbers.OG&E anticipates the combustion turbines for the Mustang Modernization Plan will be$424.9 million. As ofJune 30, 2016, OG&E has incurred $103.6 millionon the Mustang Modernization Plan.

Mustang Modernization Plan-Arkansas

On April 13, 2016, OG&E filed an application at the APSC seeking authority to construct combustion turbines at its existing Mustang generating facility.  Arkansas law requires a public utility to seek approval from the APSC to construct a power-generating facility located outside the boundaries of the state of Arkansas.  The application did not seek any cost recovery for the capital expenditures in the application, as cost recovery will be determined in future proceedings.  On July 28, 2016, OG&E filed a motion to dismiss the APSC Mustang proceeding.  OG&E intends to seek cost recovery of the Mustang combustion turbines at a later date after the Mustang facility is placed in service.

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 millionand a10.25 percentreturn on equity based on a common equity percentage of53 percent. The rate case was based on a June 30, 2015 test year and included recovery of$1.6 billionof 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 millionannual rate increase based on a return on equity of9.25 percentand a common equity percentage of 53.0 percent.  Included in the PUD Staff's recommendation is a reduction of$33.0 millionto 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 millionbased on a return on equity of 9.25 percentand a common equity percentage of50 percent, as well as a recommendation to reduce rates$13.7 millionbased on a return on equity of8.90 percentand a common equity percentage of53 percent.  Included in the Attorney General's recommendation is a reduction of$20.9 millionto OG&E’s requested increase for depreciation and plant dismantlement.

The Oklahoma Industrial Electric Consumers recommended a$47.9 millionannual rate decrease based on a return on equity of9.00 percentand a common equity percentage of53 percent.  Included in the Oklahoma Industrial Electric Consumers' recommendation is a reduction of$52.5 millionto 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. On July 1, 2016, OG&E implemented an annual interim rate increase of$69.5 millionwhile simultaneously reducing fuel costs billed to customers. The interim rates are subject to refund of any amount recovered in excess of the rates ultimately approved by the OCC in the rate case.

Arkansas Rate Case Filing

OG&E intends to file a general rate case in Arkansas with the APSC during the third quarter of 2016.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 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 segmentgenerates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operationsare conducted through OG&E andare subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company.OG&E is the largest electric utility in Oklahoma and its franchised service territory includes Fort Smith, Arkansas and the surrounding communities.  OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

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

Enable was formed effective May 1, 2013by 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 andthe Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable.The Company determined that its contribution of Enogex LLC to Enable met the requirements of being in substance real estate and was recorded at historical cost. The general partner of Enable is equally controlled by 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 atJune 30, 2016andDecember 31, 2015, the results of its operations for the three and six months endedJune 30, 2016and2015 and its cash flows for thesix months endedJune 30, 2016and2015, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company'soperating results for thethree and six months endedJune 30, 2016are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2016or 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 2015Form 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.

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]

Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

Investment in Unconsolidated Affiliate

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable. The Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2016. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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

Fair Value of Financial Instruments, Policy [Policy Text Block]

The classification of the Company's fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3).  Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  The three levels defined in the fair value hierarchy are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability.  Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk).

The fair value of the Company's long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy with the exception of the Tinker Debt which fair value is based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.

Income Tax, Policy [Policy Text Block]

Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss.  Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E earns both Federal and Oklahoma state tax credits associated with production from its wind farms and earns Oklahoma state tax credits associated with its investments in electric generating facilities which further reduce the Company's effective tax rate.

The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions.

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Share

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

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 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:

	June 30,		December 31,
(In millions)	2016		2015
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	43.9	$	36.6
SPP cost tracker rider under recovery (A)	7.5		4.5
Other (A)	11.8		5.4
Total Current Regulatory Assets	$	63.2	$	46.5
Non-Current
Benefit obligations regulatory asset	$	237.3	$	242.2
Income taxes recoverable from customers, net	58.3		56.7
Smart Grid	43.5		43.6
Deferred storm expenses	31.8		27.6
Unamortized loss on reacquired debt	14.1		14.8
Other	16.9		17.3
Total Non-Current Regulatory Assets	$	401.9	$	402.2
Regulatory Liabilities
Current
Fuel clause over recoveries	$	41.3	$	61.3
Other (B)	4.5		7.5
Total Current Regulatory Liabilities	$	45.8	$	68.8
Non-Current
Accrued removal obligations, net	$	256.2	$	254.9
Pension tracker	26.7		17.7
Other (C)	1.0		1.0
Total Non-Current Regulatory Liabilities	$	283.9	$	273.6

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

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

(C) Prior year amount of$1.0 millionreclassified 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 thesix months endedJune 30, 2016and2015.

	Six Months Ended June 30,
(In millions)	2016		2015
Balance at January 1	$	63.3	$	58.6
Accretion expense	1.4		1.3
Liabilities settled	—		(0.5		)
Balance at June 30	$	64.7	$	59.4

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

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to the Company during the six months endedJune 30, 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 income		Prior service cost			Total
Balance at December 31, 2015	$	(39.2	)	$	0.1	$	2.5	$	1.5		$	(35.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.5			—		—		(0.8		)	0.7
Settlement cost	5.0			—		—		—			5.0
Net current period other comprehensive income (loss)	6.5			—		—		(0.8		)	5.7
Balance at June 30, 2016	$	(32.7	)	$	0.1	$	2.5	$	0.7		$	(29.4	)

	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)	1.2			—		0.6			(0.9		)	0.9
Balance at June 30, 2015	$	(35.6	)	$	0.1	$	(7.4	)	$	2.4		$	(40.5	)

Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and six months endedJune 30, 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						Six Months Ended
	June 30,						June 30,
(In millions)	2016			2015			2016			2015
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.1	)	$	(1.4	)	$	(2.3	)	$	(2.6	)	(A)
Settlement	(8.2		)	—			(8.2		)	—			(A)
	(9.3		)	(1.4		)	(10.5		)	(2.6		)	Total before tax
	(3.6		)	(0.6		)	(4.0		)	(1.4		)	Tax benefit
	$	(5.7	)	$	(0.8	)	$	(6.5	)	$	(1.2	)	Net of tax
Amortization of postretirement benefit plan items
Actuarial losses	$	—		$	(0.6	)	$	—		$	(1.0	)	(A)
Prior service credit	0.7			0.7			1.3			1.4			(A)
	0.7			0.1			1.3			0.4			Total before tax
	0.3			—			0.5			0.1			Tax expense
	$	0.4		$	0.1		$	0.8		$	0.3		Net of tax
Total reclassifications for the period	$	(5.3	)	$	(0.7	)	$	(5.7	)	$	(0.9	)	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).

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Investment in Unconsolidated Affiliates (Tables)

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

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 thethree and six months endedJune 30, 2016 and 2015.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2016		2015		2016		2015
(In millions)
OGE's share of Enable net income	$	9.1	$	20.6	$	30.4	$	44.4
Amortization of basis difference	3.0		3.6		5.9		7.1
Elimination of Enogex Holdings fair value and other adjustments	4.6		4.0		8.7		8.4
Equity in earnings of unconsolidated affiliates	$	16.7	$	28.2	$	45.0	$	59.9

Schedule of Related Party Transactions [Table Text Block]

The following table summarizes related party transactions between OG&E and Enable, during thethree and six months endedJune 30, 2016 and 2015.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Operating Revenues:
Electricity to power electric compression assets	$	3.0	$	3.6	$	5.3	$	6.7
Cost of Sales:
Natural gas transportation services	$	8.8	$	8.7	$	17.5	$	17.5
Natural gas purchases/(sales)	5.4		2.1		6.9		4.6

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

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2016 and December 31, 2015 and for the three and six months endedJune 30, 2016 and 2015.

	June 30,		December 31,
Balance Sheet	2016		2015
(In millions)
Current assets	$	349	$	381
Non-current assets	10,851		10,845
Current liabilities	301		615
Non-current liabilities	3,150		3,080

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Income Statement	2016		2015		2016		2015
(In millions)
Operating revenues	$	529	$	590	$	1,038	$	1,206
Cost of natural gas and natural gas liquids	254		277		449		569
Operating income	57		93		160		197
Net income	35		77		121		168

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of Fair Value and Carrying Amount of PRM Financial Instruments [Table Text Block]

The following table summarizes the fair value and carrying amount of the Company's financial instruments at June 30, 2016 and December 31, 2015.

	June 30,				December 31,
	2016				2015
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
Senior Notes	$	2,384.7	$	2,812.5	$	2,493.9	$	2,754.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.9		10.3		10.0		9.2
OGE Energy Senior Notes	99.7		99.9		99.5		99.9

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2016

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

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

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree and six months endedJune 30, 2016 and 2015related to the Company's performance units and restricted stock.

	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015
Performance units
Total shareholder return	$	1.1	$	1.9	$	2.2	$	3.8
Earnings per share	0.4		0.6		1.0		1.1
Total performance units	1.5		2.5		3.2		4.9
Restricted stock	0.1		0.1		0.1		0.1
Total compensation expense	1.6		2.6		3.3		5.0
Less: Amount paid by unconsolidated affiliates	—		0.2		—		0.5
Net compensation expense	$	1.6	$	2.4	$	3.3	$	4.5
Income tax benefit	$	0.7	$	1.0	$	1.3	$	1.8

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Common Equity (Tables)

6 Months Ended

Jun. 30, 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 June 30,				Six Months Ended June 30,
(In millions except per share data)	2016		2015		2016		2015
Net income	$	71.5	$	87.5	$	96.7	$	130.7
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.6		199.7		199.6
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.1		—		0.1		—
Diluted average common shares outstanding	199.8		199.6		199.8		199.6
Basic Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Diluted Earnings Per Average Common Share	$	0.35	$	0.44	$	0.48	$	0.66
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2016

Long-term Debt, Unclassified [Abstract]

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

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

SERIES			DATE DUE	AMOUNT
				(In millions)
0.05%	-	0.45%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.07%	-	0.45%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.45%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

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Short-Term Debt and Credit Facilities (Tables)

6 Months Ended

Jun. 30, 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 agreement at June 30, 2016.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
(In millions)
OGE Energy (B)	$	750.0	$	284.4	0.76	%	(D)	December 13, 2018	(E)
OG&E (C)	400.0		1.7		0.95	%	(D)	December 13, 2018	(E)
Total	$	1,150.0	$	286.1	0.76	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2016.

(B) This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.  

(C) This bank facility is available to back up OG&E's commercial paper borrowings and to provide revolving credit borrowings.  This bank facility can also be used as a letter of credit facility.

(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

(E) As of June 30, 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.

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Retirement Plans and Postretirement Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

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

Net Periodic Benefit Cost

	Pension Plan												Restoration of Retirement Income Plan
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)			2016 (B)		2015 (B)		2016 (C)		2015 (C)
Service cost	$	3.5		$	3.4		$	7.9		$	7.9		$	0.1	$	0.2	$	0.2	$	0.6
Interest cost	6.1			6.6			12.7			13.0			0.1		0.1		0.2		0.3
Expected return on plan assets	(10.2		)	(11.7		)	(20.7		)	(23.5		)	—		—		—		—
Amortization of net loss	4.0			5.4			8.2			9.7			0.1		0.2		0.3		0.3
Amortization of unrecognized prior service cost (A)	—			0.1			—			0.2			—		0.1		—		0.1
Settlement	—			—			—			—			8.7		—		8.7		—
Total net periodic benefit cost	3.4			3.8			8.1			7.3			9.0		0.6		9.4		1.3
Less: Amount paid by unconsolidated affiliates	1.2			1.0			2.5			2.1			0.2		0.1		0.2		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	2.2		$	2.8		$	5.6		$	5.2		$	8.8	$	0.5	$	9.2	$	1.2

(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$11.0 millionand$3.3 millionof net periodic benefit cost recognizedduring thethree months endedJune 30, 2016and2015, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedJune 30, 2016and2015of$2.6 millionand$2.4 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thethree months endedJune 30, 2016 of $0.6 millionrelated tothe pension settlement charge of$8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thethree months endedJune 30, 2016 of $0.1 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$8.7 million.

(C) In addition to the$14.8 millionand$6.4 millionof net periodic benefit cost recognizedduring thesix months endedJune 30, 2016and2015, respectively, OG&E recognized the following:

• an increase in pension expense during thesix months endedJune 30, 2016and2015of$4.9 millionand$5.4 million, respectively,to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1);

• a deferral of pension expense during thesix months endedJune 30, 2016 of $0.6 millionrelated tothe pension settlement charge of$8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and

• a deferral of pension expense during thesix months endedJune 30, 2016 of $0.1 millionrelated tothe Arkansas jurisdictional portion ofthe pension settlement charge of$8.7 million.

	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2016 (B)			2015 (B)			2016 (C)			2015 (C)
Service cost	$	0.1		$	0.3		$	0.4		$	0.8
Interest cost	2.4			2.5			4.7			5.1
Expected return on plan assets	(0.5		)	(0.6		)	(1.1		)	(1.2		)
Amortization of net loss	0.8			3.5			1.3			6.9
Amortization of unrecognized prior service cost (A)	(2.2		)	(4.2		)	(4.4		)	(8.3		)
Total net periodic benefit cost	0.6			1.5			0.9			3.3
Less: Amount paid by unconsolidated affiliates	—			0.3			0.1			0.6
Net periodic benefit cost (net of unconsolidated affiliates)	$	0.6		$	1.2		$	0.8		$	2.7

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

(B) In addition to the$0.6 millionand$1.2 millionof net periodic benefit cost recognizedduring thethree months endedJune 30, 2016and2015, respectively, OG&E recognized an increase in postretirement medical expense duringthethree months endedJune 30, 2016and2015of$2.0 millionand$1.5 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C) In addition to the$0.8 millionand$2.7 millionof net periodic benefit cost recognizedduring thesix months endedJune 30, 2016and2015, respectively, OG&E recognized an increase in postretirement medical expense duringthesix months endedJune 30, 2016and2015of$4.0 millionand$2.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2016		2015		2016		2015
Capitalized portion of net periodic pension benefit cost	$	0.8	$	1.2	$	2.0	$	2.0
Capitalized portion of net periodic postretirement benefit cost	0.2		0.4		0.4		0.9

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Report of Business Segments (Tables)

6 Months Ended

Jun. 30, 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 during the three and six months endedJune 30, 2016 and 2015.

Three Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	551.4	$	—		$	—		$	—		$	551.4
Cost of sales	197.7		—			—			—			197.7
Other operation and maintenance	124.8		7.8			(5.0		)	—			127.6
Depreciation and amortization	78.4		—			1.7			—			80.1
Taxes other than income	19.1		—			1.0			—			20.1
Operating income (loss)	131.4		(7.8		)	2.3			—			125.9
Equity in earnings of unconsolidated affiliates	—		16.7			—			—			16.7
Other income (expense)	7.0		—			(1.4		)	(0.1		)	5.5
Interest expense	35.0		—			1.1			(0.1		)	36.0
Income tax expense (benefit)	31.1		9.3			0.2			—			40.6
Net income (loss)	$	72.3	$	(0.4	)	$	(0.4	)	$	—		$	71.5
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2

Three Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	549.9	$	—		$	—		$	—		$	549.9
Cost of sales	210.9		—			—			—			210.9
Other operation and maintenance	115.6		0.2			(2.6		)	—			113.2
Depreciation and amortization	74.3		—			1.9			—			76.2
Taxes other than income	21.6		—			0.8			—			22.4
Operating income (loss)	127.5		(0.2		)	(0.1		)	—			127.2
Equity in earnings of unconsolidated affiliates	—		28.2			—			—			28.2
Other income (expense)	4.4		—			0.8			(0.1		)	5.1
Interest expense	37.3		—			0.8			(0.1		)	38.0
Income tax expense (benefit)	25.6		10.0			(0.6		)	—			35.0
Net income (loss)	$	69.0	$	18.0		$	0.5		$	—		$	87.5
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1

Six Months Ended June 30, 2016	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	984.5	$	—		$	—		$	—		$	984.5
Cost of sales	375.6		—			—			—			375.6
Other operation and maintenance	241.1		8.0			(7.6		)	—			241.5
Depreciation and amortization	155.1		—			3.5			—			158.6
Taxes other than income	42.7		—			2.3			—			45.0
Operating income (loss)	170.0		(8.0		)	1.8			—			163.8
Equity in earnings of unconsolidated affiliates	—		45.0			—			—			45.0
Other income (expense)	12.3		—			(1.1		)	(0.2		)	11.0
Interest expense	70.5		—			2.0			(0.2		)	72.3
Income tax expense (benefit)	33.4		19.4			(2.0		)	—			50.8
Net income (loss)	$	78.4	$	17.6		$	0.7		$	—		$	96.7
Investment in unconsolidated affiliates	$	—	$	1,168.8		$	—		$	—		$	1,168.8
Total assets	$	8,380.2	$	1,481.8		$	94.9		$	(297.7	)	$	9,659.2

Six Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.0	$	—		$	—		$	—		$	1,030.0
Cost of sales	422.5		—			—			—			422.5
Other operation and maintenance	229.9		1.0			(6.0		)	—			224.9
Depreciation and amortization	148.1		—			4.0			—			152.1
Taxes other than income	44.7		—			2.2			—			46.9
Operating income (loss)	184.8		(1.0		)	(0.2		)	—			183.6
Equity in earnings of unconsolidated affiliates	—		59.9			—			—			59.9
Other income (expense)	7.3		—			3.3			(0.1		)	10.5
Interest expense	74.1		—			1.4			(0.1		)	75.4
Income tax expense (benefit)	31.9		18.1			(2.1		)	—			47.9
Net income (loss)	$	86.1	$	40.8		$	3.8		$	—		$	130.7
Investment in unconsolidated affiliates	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,315.7	$	1,486.6		$	121.8		$	(348.0	)	$	9,576.1

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Summary of Significant Accounting Policies Equity Ownership (Details)	Jun. 30, 2016
CenterPoint [Member]
Percentage Share of Management Rights	50.00%
OGE Energy [Member]
Percentage Share of Management Rights	50.00%

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Regulated Operations (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause over recoveries		$ 41.3	$ 61.3
Current Regulatory Assets		63.2	46.5
Non-Current Regulatory Assets		401.9	402.2
Current Regulatory Liabilities		45.8	68.8
Non-Current Regulatory Liabilities		283.9	273.6
Prior Period Reclassification Adjustment		1.0
Other Regulatory Liability [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	4.5	7.5
Non-Current Regulatory Liabilities	[2]	1.0	1.0
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		256.2	254.9
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		26.7	17.7
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[3]	43.9	36.6
Other Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[3]	11.8	5.4
Non-Current Regulatory Assets		16.9	17.3
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		237.3	242.2
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		58.3	56.7
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		43.5	43.6
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		31.8	27.6
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		14.1	14.8
SPP Cost Tracker Rider Under Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[3]	$ 7.5	$ 4.5

[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.

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Summary of Significant Accounting Policies Asset Retirement Obligation (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 63.3	$ 58.6
Accretion expense	1.4	1.3
Liabilities settled	0.0	(0.5)
Balance at June 30	$ 64.7	$ 59.4

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (29.4)	$ (40.5)	$ (35.1)	$ (41.4)
Amounts reclassified from accumulated other comprehensive income (loss)	0.7	0.9
Net current period other comprehensive income (loss)	5.7
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	(32.7)	(35.6)	(39.2)	(36.8)
Amounts reclassified from accumulated other comprehensive income (loss)	1.5	1.2
Net current period other comprehensive income (loss)	6.5
Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	2.5	(7.4)	2.5	(8.0)
Amounts reclassified from accumulated other comprehensive income (loss)	0.0	0.6
Net current period other comprehensive income (loss)	0.0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	0.1	0.1	0.1	0.1
Amounts reclassified from accumulated other comprehensive income (loss)	0.0	0.0
Net current period other comprehensive income (loss)	0.0
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	0.7	2.4	$ 1.5	$ 3.3
Amounts reclassified from accumulated other comprehensive income (loss)	(0.8)	$ (0.9)
Net current period other comprehensive income (loss)	(0.8)
Settlement Cost [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	5.0
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Pension Plan [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	5.0
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) [Member] | Other Postretirement Benefit Plan [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	0.0
Settlement Cost [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) [Member] | Other Postretirement Benefit Plan [Member]
Amounts reclassified from accumulated other comprehensive income (loss)	$ 0.0

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) Reclassifications out of AOCI (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ (5.3)	$ (0.7)	$ (5.7)	$ (0.9)
Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	[1]	(1.1)	(1.4)	(2.3)	(2.6)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Settlement Cost, before Tax	[1]	(8.2)	0.0	(8.2)	0.0
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		(9.3)	(1.4)	(10.5)	(2.6)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		(3.6)	(0.6)	(4.0)	(1.4)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(5.7)	(0.8)	(6.5)	(1.2)
Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	[1]	0.0	(0.6)	0.0	(1.0)
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	[1]	0.7	0.7	1.3	1.4
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		0.7	0.1	1.3	0.4
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		0.3	0.0	0.5	0.1
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ 0.4	$ 0.1	$ 0.8	$ 0.3

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

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Reclassifications (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Prior Period Reclassification Adjustment	$ 1.0
Adjustments for New Accounting Pronouncement [Member]
Prior Period Reclassification Adjustment	$ 16.8

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Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Apr. 30, 2014	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	May 13, 2014	May 01, 2013
Limited Partner Units Owned		111,000,000		111,000,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit				$ 0.31800
Equity in earnings of unconsolidated affiliates		$ 16.7	$ 28.2	$ 45.0	$ 59.9
percentage of subsidiary contributed						24.95%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		768.7		768.7
Enogex LLC [Member]
Percentage of Enogex LLC Contributed							100.00%
Increase in fair value of net assets							$ 2,200.0
Enable Midstream Partners [Member]
Partners' Capital Account, Units, Sold in Public Offering	25,000,000
Distributions from unconsolidated affiliates		$ 35.3	$ 34.6	$ 70.6	$ 68.9
CenterPoint [Member]
Percent of Incentive Distribution Rights		40.00%		40.00%
OGE Holdings [Member]
Subordinated Units Held by Limited Partners of the LLC or LP.				68,200,000
Percent of Incentive Distribution Rights		60.00%		60.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest				26.30%

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Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 0.0		$ 0.0		$ 1.7
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	3.0	$ 3.6	5.3	$ 6.7
Operating Costs Charged [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	1.3	2.5	2.6	5.3
Employment Costs [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	7.0	8.1	14.1	18.1
Natural Gas Transportation [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	8.8	8.7	17.5	17.5
Natural Gas Purchases [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	5.4	$ 2.1	6.9	$ 4.6
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 2.8		$ 2.8		$ 3.4

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Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 349.0	$ 381.0
Non-current assets	10,851.0	10,845.0
Current liabilities	301.0	615.0
Non-current liabilities	$ 3,150.0	$ 3,080.0

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Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Schedule of Equity Method Investments [Line Items]
Operating revenues	$ 529.0	$ 590.0	$ 1,038.0	$ 1,206.0
Cost of natural gas and natural gas liquids	254.0	277.0	449.0	569.0
Operating income	57.0	93.0	160.0	197.0
Net income	$ 35.0	$ 77.0	$ 121.0	$ 168.0

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Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
OGE's share of Enable net income	$ 9.1	$ 20.6	$ 30.4	$ 44.4
Amortization of basis difference	3.0	3.6	5.9	7.1
Elimination of Enogex Holdings fair value and other adjustments	4.6	4.0	8.7	8.4
Equity in earnings of unconsolidated affiliates	$ 16.7	$ 28.2	$ 45.0	$ 59.9

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Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 2,384.7	$ 2,493.9
Long-Term Debt, Fair Value	2,812.5	2,754.6
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	135.4	135.4
Long-Term Debt, Fair Value	135.4	135.4
OG&E Tinker Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	9.9	10.0
Long-Term Debt, Fair Value	10.3	9.2
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	99.7	99.5
Long-Term Debt, Fair Value	99.9	99.9
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0.0	$ 0.0

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Stock-Based Compensation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Stock-Based Compensation Activity
Income tax benefit	$ 0.7	$ 1.0	$ 1.3	$ 1.8
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	1.5	2.5	3.2	4.9
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	0.1	0.1	0.1	0.1
Stock Compensation Plan [Member]
Stock-Based Compensation Activity
Compensation expense	1.6	2.6	3.3	5.0
Less: Amount paid by unconsolidated affiliates	0.0	0.2	0.0	0.5
Net compensation expense	1.6	2.4	3.3	4.5
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	1.1	1.9	2.2	3.8
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 0.4	$ 0.6	$ 1.0	$ 1.1

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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - Automatic Dividend Reinvestment and Stock Purchase Plan [Member]	3 Months Ended	6 Months Ended
	Jun. 30, 2016 shares	Jun. 30, 2016 shares
Stock Issued During Period, Shares, New Issues	0	0
Shares Held in Reserve Related to Dividend Reinvestment Plan and Stock Purchase Plan	4,774,442	4,774,442

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Common Equity Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Equity [Abstract]
Net income	$ 71.5	$ 87.5	$ 96.7	$ 130.7
Basic average common shares outstanding	199.7	199.6	199.7	199.6
Contingently issuable shares (performance and restricted stock units)	0.1	0.0	0.1	0.0
Diluted average common shares outstanding	199.8	199.6	199.8	199.6
Earnings Per Share, Basic and Diluted [Abstract]
Basic Earnings Per Average Common Share	$ 0.35	$ 0.44	$ 0.48	$ 0.66
Diluted Earnings Per Average Common Share	$ 0.35	$ 0.44	$ 0.48	$ 0.66
Anti-dilutive shares excluded from earnings per share calculation	0.0	0.0	0.0	0.0

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Long-Term Debt (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Debt Instrument [Line Items]
Percent of Principal Amount Subject to Optional Tender	100.00%
Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jan. 01, 2025
Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 01, 2027
Redeemable during the next 12 months
Debt Instrument [Line Items]
Long-term debt	$ 135.4
OG&E [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Long term debt	47.0
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Long term debt	32.4
OG&E [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Long term debt	$ 56.0
Minimum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.07%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.05%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.45%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.45%
Maximum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.45%

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Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Short-term debt		$ 284.4	$ 0.0
Line of Credit Facility [Abstract]
Aggregate Commitment		1,150.0
Amount Outstanding	[1]	$ 286.1
Weighted Average Interest Rate		0.76%
Intercompany Borrowing Agreement, Expiration Date		Dec. 13, 2017
OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment	[2]	$ 750.0
Amount Outstanding	[1],[2]	$ 284.4
Weighted Average Interest Rate	[2],[3]	0.76%
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
Short Term Borrowing Capacity That Has Regulatory Approval		$ 800.0
Period For Which Regulatory Approval Has Been Given to Acquire Short Term Debt		2 years
December 13, 2017 [Domain] | OGE Energy [Member]
Line of Credit Facility [Abstract]
Aggregate Commitment		$ 16.3
December 13, 2017 [Domain] | 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 June 30, 2016.

[2] This bank facility is available to back up OGE Energy's commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility.

[3] Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.

[4] As of June 30, 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.

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Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		1 Months Ended	3 Months Ended				6 Months Ended
		Jul. 31, 2016	Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Pension Contributions		$ 20.0
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost (net of unconsolidated affiliates)			$ 11.0		$ 3.3		$ 14.8		$ 6.4
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			3.5		3.4		7.9		7.9
Interest cost			6.1		6.6		12.7		13.0
Expected return on plan assets			(10.2)		(11.7)		(20.7)		(23.5)
Amortization of net loss			4.0		5.4		8.2		9.7
Amortization of unrecognized prior service cost	[1]		0.0		0.1		0.0		0.2
Settlement			0.0		0.0		0.0		0.0
Total net periodic benefit cost			3.4		3.8		8.1		7.3
Less: Amount paid by unconsolidated affiliates			1.2		1.0		2.5		2.1
Net periodic benefit cost (net of unconsolidated affiliates)			2.2	[2]	2.8	[2]	5.6	[3]	5.2	[3]
Capitalized Portion of Net Periodic Benefit Cost			0.8		1.2		2.0		2.0
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			0.1		0.2		0.2		0.6
Interest cost			0.1		0.1		0.2		0.3
Expected return on plan assets			0.0		0.0		0.0		0.0
Amortization of net loss			0.1		0.2		0.3		0.3
Amortization of unrecognized prior service cost	[1]		0.0		0.1		0.0		0.1
Settlement			8.7		0.0		8.7		0.0
Total net periodic benefit cost			9.0		0.6		9.4		1.3
Less: Amount paid by unconsolidated affiliates			0.2		0.1		0.2		0.1
Net periodic benefit cost (net of unconsolidated affiliates)			8.8	[2]	0.5	[2]	9.2	[3]	1.2	[3]
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements							(8.7)
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			0.1		0.3		0.4		0.8
Interest cost			2.4		2.5		4.7		5.1
Expected return on plan assets			(0.5)		(0.6)		(1.1)		(1.2)
Amortization of net loss			0.8		3.5		1.3		6.9
Amortization of unrecognized prior service cost	[4]		(2.2)		(4.2)		(4.4)		(8.3)
Total net periodic benefit cost			0.6		1.5		0.9		3.3
Less: Amount paid by unconsolidated affiliates			0.0		0.3		0.1		0.6
Net periodic benefit cost (net of unconsolidated affiliates)			0.6	[5]	1.2	[5]	0.8	[6]	2.7	[6]
Capitalized Portion of Net Periodic Benefit Cost			0.2		0.4		0.4		0.9
OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements			2.6		2.4		4.9		5.4
OKLAHOMA | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Settlement			0.6
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements							(0.6)
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements			2.0		$ 1.5		4.0		$ 2.9
ARKANSAS | Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Settlement			$ 0.1
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements							$ (0.1)

[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 $11.0 million and $3.3 million of net periodic benefit cost recognized during the three months ended June 30, 2016 and 2015, respectively, OG&E recognized the following:•an increase in pension expense during the three months ended June 30, 2016 and 2015 of $2.6 million and $2.4 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1); •a deferral of pension expense during the three months ended June 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and•a deferral of pension expense during the three months ended June 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million.

[3] In addition to the $14.8 million and $6.4 million of net periodic benefit cost recognized during the six months ended June 30, 2016 and 2015, respectively, OG&E recognized the following: •an increase in pension expense during the six months ended June 30, 2016 and 2015 of $4.9 million and $5.4 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1); •a deferral of pension expense during the six months ended June 30, 2016 of $0.6 million related to the pension settlement charge of $8.7 million, in accordance with the Oklahoma Pension tracker regulatory liability (see Note 1); and•a deferral of pension expense during the six months ended June 30, 2016 of $0.1 million related to the Arkansas jurisdictional portion of the pension settlement charge of $8.7 million.

[4] 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.

[5] In addition to the $0.6 million and $1.2 million of net periodic benefit cost recognized during the three months ended June 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended June 30, 2016 and 2015 of $2.0 million and $1.5 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).

[6] In addition to the $0.8 million and $2.7 million of net periodic benefit cost recognized during the six months ended June 30, 2016 and 2015, respectively, OG&E recognized an increase in postretirement medical expense during the six months ended June 30, 2016 and 2015 of $4.0 million and $2.9 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

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Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 551.4	$ 549.9	$ 984.5	$ 1,030.0
Cost of sales	197.7	210.9	375.6	422.5
Other operation and maintenance	127.6	113.2	241.5	224.9
Depreciation and amortization	80.1	76.2	158.6	152.1
Taxes other than income	20.1	22.4	45.0	46.9
OPERATING INCOME	125.9	127.2	163.8	183.6
Equity in earnings of unconsolidated affiliates	16.7	28.2	45.0	59.9
Other income (expense)	5.5	5.1	11.0	10.5
Interest expense	36.0	38.0	72.3	75.4
Income tax expense (benefit)	40.6	35.0	50.8	47.9
Net income (loss)	71.5	87.5	96.7	130.7
Investment in unconsolidated affiliates	1,168.8	1,309.2	1,168.8	1,309.2	$ 1,194.4
Total assets	9,659.2	9,576.1	9,659.2	9,576.1	$ 9,580.6
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	551.4	549.9	984.5	1,030.0
Cost of sales	197.7	210.9	375.6	422.5
Other operation and maintenance	124.8	115.6	241.1	229.9
Depreciation and amortization	78.4	74.3	155.1	148.1
Taxes other than income	19.1	21.6	42.7	44.7
OPERATING INCOME	131.4	127.5	170.0	184.8
Equity in earnings of unconsolidated affiliates	0.0	0.0	0.0	0.0
Other income (expense)	7.0	4.4	12.3	7.3
Interest expense	35.0	37.3	70.5	74.1
Income tax expense (benefit)	31.1	25.6	33.4	31.9
Net income (loss)	72.3	69.0	78.4	86.1
Investment in unconsolidated affiliates	0.0	0.0	0.0	0.0
Total assets	8,380.2	8,315.7	8,380.2	8,315.7
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0	0.0
Cost of sales	0.0	0.0	0.0	0.0
Other operation and maintenance	7.8	0.2	8.0	1.0
Depreciation and amortization	0.0	0.0	0.0	0.0
Taxes other than income	0.0	0.0	0.0	0.0
OPERATING INCOME	(7.8)	(0.2)	(8.0)	(1.0)
Equity in earnings of unconsolidated affiliates	16.7	28.2	45.0	59.9
Other income (expense)	0.0	0.0	0.0	0.0
Interest expense	0.0	0.0	0.0	0.0
Income tax expense (benefit)	9.3	10.0	19.4	18.1
Net income (loss)	(0.4)	18.0	17.6	40.8
Investment in unconsolidated affiliates	1,168.8	1,309.2	1,168.8	1,309.2
Total assets	1,481.8	1,486.6	1,481.8	1,486.6
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0	0.0
Cost of sales	0.0	0.0	0.0	0.0
Other operation and maintenance	(5.0)	(2.6)	(7.6)	(6.0)
Depreciation and amortization	1.7	1.9	3.5	4.0
Taxes other than income	1.0	0.8	2.3	2.2
OPERATING INCOME	2.3	(0.1)	1.8	(0.2)
Equity in earnings of unconsolidated affiliates	0.0	0.0	0.0	0.0
Other income (expense)	(1.4)	0.8	(1.1)	3.3
Interest expense	1.1	0.8	2.0	1.4
Income tax expense (benefit)	0.2	(0.6)	(2.0)	(2.1)
Net income (loss)	(0.4)	0.5	0.7	3.8
Investment in unconsolidated affiliates	0.0	0.0	0.0	0.0
Total assets	94.9	121.8	94.9	121.8
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0	0.0
Cost of sales	0.0	0.0	0.0	0.0
Other operation and maintenance	0.0	0.0	0.0	0.0
Depreciation and amortization	0.0	0.0	0.0	0.0
Taxes other than income	0.0	0.0	0.0	0.0
OPERATING INCOME	0.0	0.0	0.0	0.0
Equity in earnings of unconsolidated affiliates	0.0	0.0	0.0	0.0
Other income (expense)	(0.1)	(0.1)	(0.2)	(0.1)
Interest expense	(0.1)	(0.1)	(0.2)	(0.1)
Income tax expense (benefit)	0.0	0.0	0.0	0.0
Net income (loss)	0.0	0.0	0.0	0.0
Investment in unconsolidated affiliates	0.0	0.0	0.0	0.0
Total assets	$ (297.7)	$ (348.0)	$ (297.7)	$ (348.0)

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Rate Matters and Regulation Rate Matters and Regulation (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Annual Recovery of Lost Revenues Through Rate Implementation	$ 10.0
Additional Requested Plant Dismantlement Cost	$ 8.0
Change in Requested Return on Equity	0.25%
Change in Requested Rate Increase	$ 9.0
Public Utilities, Interim Rate Increase (Decrease), Amount	69.5
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	21.4
Lost Revenue Collected from Customers	15.2
SmartHours Program [Member] | Oklahoma Public Utility Division Staff [Member]
Lost Revenue Associated with Customer Programs				2.6
Reduction of Revenue				$ 7.5
Dry Scrubber Project [Member]
Estimated Environmental Capital Costs	547.5
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	116.8
Mustang Modernization [Member]
Estimated Environmental Capital Costs	424.9
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	103.6
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
Oklahoma Attorney General [Member]
Reduction to Requested Additional Plant Dismantlement Costs	$ 20.9
Oklahoma Public Utility Division Staff [Member]
Recommended Return on Equity	9.25%
Recommended Common Equity Percentage	53.00%
Reduction to Requested Additional Plant Dismantlement Costs	$ 33.0
Recommended Rate Increase (Decrease)	$ 6.1
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 Increase (Decrease)	$ 47.9
Recommendation 1 [Member] | Oklahoma Attorney General [Member]
Recommended Return on Equity	9.25%
Recommended Common Equity Percentage	50.00%
Recommended Rate Increase (Decrease)	$ 10.8
Recommendation 2 [Member] | Oklahoma Attorney General [Member]
Recommended Return on Equity	8.90%
Recommended Common Equity Percentage	53.00%
Recommended Rate Increase (Decrease)	$ 13.7