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 endedMarch 31, 2017

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, a smaller reporting company, or an emerging growth company.  See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth 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
	Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 March 31, 2017, there were 199,704,099 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDEDMARCH 31, 2017

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	24
Item 3. Quantitative and Qualitative Disclosures About Market Risk	40
Item 4. Controls and Procedures	40
Part II - OTHER INFORMATION
Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 6. Exhibits	41
Signature	42

i

GLOSSARY OF TERMS

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

Abbreviation	Definition
2016 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2016
ALJ	Administrative Law Judge
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC and Bronco Midstream Holdings II, LLC, collectively
ASU	Financial Accounting Standards Board Accounting Standards Update
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2	Carbon dioxide
Company	OGE Energy Corp., 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, a 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 Plan
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
MWh	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
OCC	Oklahoma Corporation Commission
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 25.7 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
Regional Haze Rule	The EPA's regional haze rule
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
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 2016Form 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;

• the ability to obtain timely and sufficient rate relief to allow for recovery of items such as capital expenditures, fuel costs, operating costs, transmission costs and deferred expenditures;

• 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;

• the impact on demand for our services resulting from cost-competitive advances in technology, such as distributed electricity generation and customer energy efficiency programs;

• technological developments, changing markets and other factors that result in competitive disadvantages and create the potential for impairment of existing assets;

• factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, natural gas or coal supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

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

• the effect of retroactive pricing 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, safety laws or regulations that may impact the cost of operations or restrict or change the waythe Companyoperates its facilities;

• 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;

• creditworthiness of suppliers, customers and other contractual parties;

• social attitudes regarding the utility, natural gas and power industries;

• identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions and divestitures;

• increased pension and healthcare costs;

• costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including, but not limited to, those described in this Form 10-Q;

• 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" in the Company's 2016 Form 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 March 31,
(In millions except per share data)	2017			2016
OPERATING REVENUES	$	456.0		$	433.1
COST OF SALES	208.7			177.9
OPERATING EXPENSES
Other operation and maintenance	124.0			113.9
Depreciation and amortization	55.6			78.5
Taxes other than income	23.9			24.9
Total operating expenses	203.5			217.3
OPERATING INCOME	43.8			37.9
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	35.6			28.3
Allowance for equity funds used during construction	6.9			1.6
Other income	8.8			5.6
Other expense	(4.1		)	(1.7		)
Net other income (expense)	47.2			33.8
INTEREST EXPENSE
Interest on long-term debt	35.9			35.8
Allowance for borrowed funds used during construction	(3.3		)	(0.9		)
Interest on short-term debt and other interest charges	2.4			1.4
Interest expense	35.0			36.3
INCOME BEFORE TAXES	56.0			35.4
INCOME TAX EXPENSE	20.0			10.2
NET INCOME	$	36.0		$	25.2
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7			199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.0			199.7
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.18		$	0.13
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.18		$	0.13
DIVIDENDS DECLARED PER COMMON SHARE	$	0.30250		$	0.27500

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 March 31,
(In millions)	2017		2016
Net income	$	36.0	$	25.2
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 and $0.4, respectively	0.6		0.8
Postretirement Benefit Plans:
Amortization of prior service cost, net of tax of ($0.0) and ($0.2), respectively	—		(0.4		)
Other comprehensive income, net of tax	0.6		0.4
Comprehensive income	$	36.6	$	25.6

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

3

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	36.0		$	25.2
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	55.6			78.5
Deferred income taxes and investment tax credits, net	20.4			10.4
Equity in earnings of unconsolidated affiliates	(35.6		)	(28.3		)
Distributions from unconsolidated affiliates	35.3			28.7
Allowance for equity funds used during construction	(6.9		)	(1.6		)
Stock-based compensation	2.1			1.7
Regulatory assets	(6.4		)	(2.3		)
Regulatory liabilities	(4.6		)	(4.6		)
Other assets	(4.0		)	2.5
Other liabilities	6.2			2.1
Change in certain current assets and liabilities
Accounts receivable, net	36.4			38.0
Accounts receivable - unconsolidated affiliates	(3.3		)	(1.2		)
Accrued unbilled revenues	3.5			2.1
Fuel, materials and supplies inventories	(7.7		)	10.2
Fuel clause under recoveries	(22.1		)	—
Other current assets	4.3			(10.0		)
Accounts payable	24.9			(44.1		)
Fuel clause over recoveries	—			2.0
Other current liabilities	(43.1		)	(35.9		)
Net Cash Provided from Operating Activities	91.0			73.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(219.9		)	(177.7		)
Return of capital - equity method investments	—			6.6
Net Cash Used in Investing Activities	(219.9		)	(171.1		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(60.4		)	(54.9		)
Proceeds from long-term debt	297.1			—
Payment of long-term debt	(0.1		)	(110.1		)
Increase (decrease) in short-term debt	(108.0		)	187.5
Net cash provided from financing activities	128.6			22.5
NET CHANGE IN CASH AND CASH EQUIVALENTS	(0.3		)	(75.2		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	0.3			75.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—

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

4

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
(In millions)	2017		2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	0.3
Accounts receivable, less reserve of $1.1 and $1.5, respectively	136.6		173.0
Accounts receivable - unconsolidated affiliates	5.8		2.5
Accrued unbilled revenues	56.2		59.7
Income taxes receivable	13.4		19.4
Fuel inventories	86.3		79.8
Materials and supplies, at average cost	82.9		81.7
Fuel clause under recoveries	73.4		51.3
Other	83.5		81.8
Total current assets	538.1		549.5
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,158.9		1,158.6
Other	75.5		73.6
Total other property and investments	1,234.4		1,232.2
PROPERTY, PLANT AND EQUIPMENT
In service	10,730.8		10,690.0
Construction work in progress	673.3		495.1
Total property, plant and equipment	11,404.1		11,185.1
Less accumulated depreciation	3,503.8		3,488.9
Net property, plant and equipment	7,900.3		7,696.2
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	403.1		404.8
Other	59.0		56.9
Total deferred charges and other assets	462.1		461.7
TOTAL ASSETS	$	10,134.9	$	9,939.6

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

5

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)

	March 31,			December 31,
(In millions)	2017			2016
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	128.2		$	236.2
Accounts payable	244.3			205.4
Dividends payable	60.4			60.4
Customer deposits	78.6			77.7
Accrued taxes	25.2			41.3
Accrued interest	33.0			40.4
Accrued compensation	25.5			45.1
Long-term debt due within one year	224.8			224.7
Other	95.0			96.0
Total current liabilities	915.0			1,027.2
LONG-TERM DEBT	2,703.2			2,405.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	276.5			274.8
Deferred income taxes	2,332.0			2,334.5
Regulatory liabilities	306.7			299.7
Other	157.1			153.8
Total deferred credits and other liabilities	3,072.3			3,062.8
Total liabilities	6,690.5			6,495.8
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,107.9			1,105.8
Retained earnings	2,365.2			2,367.3
Accumulated other comprehensive loss, net of tax	(28.7		)	(29.3		)
Total stockholders' equity	3,444.4			3,443.8
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	10,134.9		$	9,939.6

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, 2016	$	2.0	$	1,103.8	$	2,367.3		$	(29.3	)	$	3,443.8
Cumulative effect of change in accounting principle	—		—		22.3			—			22.3
Net income	—		—		36.0			—			36.0
Other comprehensive income, net of tax	—		—		—			0.6			0.6
Dividends declared on common stock	—		—		(60.4		)	—			(60.4		)
Stock-based compensation	—		2.1		—			—			2.1
Balance at March 31, 2017	$	2.0	$	1,105.9	$	2,365.2		$	(28.7	)	$	3,444.4
Balance at December 31, 2015	$	2.0	$	1,099.3	$	2,259.8		$	(35.1	)	$	3,326.0
Net income	—		—		25.2			—			25.2
Other comprehensive income, net of tax	—		—		—			0.4			0.4
Dividends declared on common stock	—		—		(54.9		)	—			(54.9		)
Stock-based compensation	—		1.6		—			—			1.6
Balance at March 31, 2016	$	2.0	$	1,100.9	$	2,230.1		$	(34.7	)	$	3,298.3

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

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company atMarch 31, 2017andDecember 31, 2016, the results of its operations for the three months endedMarch 31, 2017and2016 and its cash flows for thethree months endedMarch 31, 2017and2016, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring afterMarch 31, 2017up to the date of issuance of these Condensed Consolidated Financial Statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company'soperating results for thethree months endedMarch 31, 2017are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2017or 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 2016Form 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:

	March 31,		December 31,
(In millions)	2017		2016
Regulatory Assets
Current
Fuel clause under recoveries	$	73.4	$	51.3
Oklahoma demand program rider under recovery (A)	45.6		51.0
SPP cost tracker under recovery (A)	14.6		10.0
Other (A)	8.6		9.5
Total Current Regulatory Assets	$	142.2	$	121.8
Non-Current
Benefit obligations regulatory asset	$	228.9	$	232.6
Income taxes recoverable from customers, net	65.6		62.3
Deferred storm expenses	40.5		35.7
Smart Grid	38.2		43.2
Unamortized loss on reacquired debt	13.1		13.4
Other	16.8		17.6
Total Non-Current Regulatory Assets	$	403.1	$	404.8
Regulatory Liabilities
Current
Other (B)	$	13.4	$	12.3
Total Current Regulatory Liabilities	$	13.4	$	12.3
Non-Current
Accrued removal obligations, net	$	268.6	$	262.8
Pension tracker	36.6		35.5
Other	1.5		1.4
Total Non-Current Regulatory Liabilities	$	306.7	$	299.7

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

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

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

9

Investment in Unconsolidated Affiliate

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable, therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at March 31, 2017. 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 thethree months endedMarch 31, 2017and2016.

	Three Months Ended March 31,
(In millions)	2017		2016
Balance at January 1	$	69.6	$	63.3
Accretion expense	0.7		0.7
Balance at March 31	$	70.3	$	64.0

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 three months endedMarch 31, 2017 and 2016. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net income  (loss)			Prior service cost		Net income (loss)		Prior service cost		Total
Balance at December 31, 2016	$	(32.1	)	$	0.1	$	2.7	$	—	$	(29.3	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.6			—		—		—		0.6
Balance at March 31, 2017	$	(31.5	)	$	0.1	$	2.7	$	—	$	(28.7	)

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

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three months endedMarch 31, 2017 and 2016.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended
	March 31,
(In millions)	2017			2016
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.0	)	$	(1.2	)	(A)
	(0.4		)	(0.4		)	Income taxes
	$	(0.6	)	$	(0.8	)	Net of tax
Amortization of postretirement benefit plan items
Prior service credit	$	—		$	0.6		(A)
	—			0.6			Total before tax
	—			0.2			Income taxes
	$	—		$	0.4		Net of tax
Total reclassifications for the period	$	(0.6	)	$	(0.4	)	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).

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 Company currently expects to apply the modified retrospective transition method, but will ultimately determine its transition approach once various industry issues have been resolved. Currently, the Company is not aware of any issues that would have a material impact on the timing of revenue recognition. The Company is assessing the effect of this new guidance on its tariff-based sales, bundled arrangements and alternative revenue programs. At this time, the Company is evaluating the impact of the new standard on its results of operations and financial position, but believes that it will change the income statement presentation of revenues and will require new disclosures.

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

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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 started evaluating its current lease contracts. The Company has not determined the amount of impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Employee Share Based Payment Accounting.In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends Accounting Standards Codification Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements.The new guidance among other requirements requires all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Previously, tax benefits in excess of compensation cost, or windfalls, were recorded in equity, and tax deficiencies, or shortfalls, were recorded in equity to the extent of previous windfalls, and then to the income statement. Under the new guidance, the windfall tax benefit is recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the previous requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The Company adopted this standard in the first quarter of 2017, and recorded a cumulative effect of $22.3 million as a deferred tax asset with an offset in retained earnings. Going forward, tax benefits in excess of compensation costs previously recorded in equity will be recorded within the income statement and all tax related cash flows resulting from share based payments will be recorded as an operating activity within the statement of cash flows.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.”  The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit expense between those that are attributed to compensation for service and those that are not.  The service cost component of benefit expense will continue to be presented within operating income, but entities will now be required to present the other components of benefit expense as non-operating within the income statement.  Additionally, the new guidance only permits the capitalization of the service cost component of net benefit expense.

The accounting change is required to be applied using a modified retrospective approach for the presentation of components of net benefit cost, and on a prospective basis for the capitalization of only the service cost component of net benefit costs.  The new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted, subject to certain conditions.

The Company believes that the impact of the change in capitalization of only the service cost component of net periodic benefit costs will be immaterial from current practice.  The Company does not intend to early adopt the new guidance and will implement the change in the first quarter of 2018.

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.

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.

Enable completed an initial public offering resulting in Enable becoming a publicly traded Master Limited Partnership in April 2014. At March 31, 2017, the Company owned 111.0 million common units, or 25.7 percent of Enable's outstanding common units. Of the Company's 111.0 million common units, 68.2 million units were subordinated. The subordination period

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began on the closing date of Enable's initial public offering and will extend until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. The Company anticipates that the subordination period will expire in August 2017 and will not impact future distributions that the Company receives from Enable.

On May 2, 2017, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $35.3 million during the three months endedMarch 31, 2017 and 2016.

On January 16, 2017, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided a second notice to the Company of CenterPoint's solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. On February 15, 2017, under the terms of right of first offer, the Company submitted to CenterPoint another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in Enable GP and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint within the required timeframe. In accordance with the provisions of the partnership agreement, CenterPoint has until July 15, 2017 to solicit additional offers in excess of the Company's offer.

If the Company's proposal had been accepted by CenterPoint, and if the transaction contemplated by the proposal was in fact consummated, the Company anticipated that the third party would, as a result of such transaction, become the owner of all or substantially all of the securities subject to the right of first offer. The Company's ownership interest in Enable would not have materially changed as a result of such transaction, and therefore the Company would not have been required to consolidate the financial results of Enable with the financial results of the Company.

The Company cannot predict what future actions CenterPoint will take, if any, associated with their ownership interest in Enable.

Related Party Transactions

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

In connection with the formation of Enable, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2017. Under these agreements, the Company charged operating costs to Enable of $0.8 million and $1.3 million for the three months endedMarch 31, 2017 and 2016, respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as such.  Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

The Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, the Company, CenterPoint and Enable agreed to continue the secondment to Enable of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $10.0 million and $8.3 million during the three months endedMarch 31, 2017 and 2016, respectively, under the Transitional Seconding Agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $20.9 million. Settlement and curtailment charges associated with the Enable seconded

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employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 day notice.

The Company had accounts receivable from Enable for amounts billed for transitional services, including the cost of seconded employees, of $5.9 million as of March 31, 2017 and $2.7 million as of December 31, 2016, respectively.

Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries.The following table summarizes related party transactions between OG&E and Enable during thethree months endedMarch 31, 2017 and 2016.

	Three Months Ended
	March 31,
(In millions)	2017			2016
Operating Revenues:
Electricity to power electric compression assets	$	2.2		$	2.3
Cost of Sales:
Natural gas transportation services	$	8.8		$	8.8
Natural gas purchases/(sales)	(0.4		)	1.5

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at March 31, 2017 and December 31, 2016 and for the three months endedMarch 31, 2017 and 2016.

	March 31,		December 31,
Balance Sheet	2017		2016
(In millions)
Current assets	$	375	$	396
Non-current assets	10,786		10,816
Current liabilities	279		362
Non-current liabilities	3,111		3,056

	Three Months Ended
	March 31,
Income Statement	2017		2016
(In millions)
Operating revenues	$	666	$	509
Cost of natural gas and natural gas liquids	308		195
Operating income	140		103
Net income	111		86

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.

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The Company recorded equity in earnings of unconsolidated affiliates of $35.6 million and $28.3 million for the three months endedMarch 31, 2017 and 2016, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in the net assets of Enable. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed, beginning in May 2013. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described below.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for thethree months endedMarch 31, 2017 and 2016.

	Three Months Ended
	March 31,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2017			2016
(In millions)
Enable net income	$	110.8		$	86.0
Differences due to timing of OGE Energy and Enable accounting close	—			(11.7		)
Enable net income used to calculate OGE Energy's equity in earnings	$	110.8		$	74.3
OGE Energy’s percent ownership at period end	25.7		%	26.3		%
OGE Energy’s portion of Enable net income	$	28.5		$	19.5
Impairments recognized by Enable associated with OGE Energy’s basis differences	—			1.8
OGE Energy's share of Enable net income	$	28.5		$	21.3
Amortization of basis difference	2.8			2.9
Elimination of Enable fair value step up	4.3			4.1
Equity in earnings of unconsolidated affiliates	$	35.6		$	28.3

The difference between the OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $736.6 million as of March 31, 2017. The following table reconciles the basis difference in Enable from December 31, 2016 to March 31, 2017.

(In millions)
Basis difference as of December 31, 2016	$	743.7
Amortization of basis difference	(2.8		)
Elimination of Enable fair value step up	(4.3		)
Basis difference as of March 31, 2017	$	736.6

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

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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 atMarch 31, 2017 and December 31, 2016.

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.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at March 31, 2017 and December 31, 2016.

	March 31,				December 31,
	2017				2016
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt (including Long-Term Debt due within one year)
Senior Notes	$	2,683.0	$	2,941.5	$	2,385.5	$	2,657.2
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.8		9.3		9.9		9.5
OGE Energy Senior Notes	99.8		100.0		99.7		99.9

5. Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree months endedMarch 31, 2017 and 2016related to the Company's performance units and restricted stock.

	Three Months Ended March 31,
(In millions)	2017		2016
Performance units
Total shareholder return	$	1.5	$	1.1
Earnings per share	0.6		0.6
Total performance units	2.1		1.7
Restricted stock	—		—
Total compensation expense	2.1		1.7
Income tax benefit	$	0.8	$	0.6

During thethree months endedMarch 31, 2017, the Company issued an immaterial number of shares to satisfy restricted stock grants.

The following table summarizes the activity of the Company's stock-based compensation during thethree months endedMarch 31, 2017.

	Units/Shares	Fair Value Per Share
Grants
Performance units (Total shareholder return)	260,570	$	41.77
Performance units (Earnings per share)	86,857	$	34.95

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 to2013or state and local tax examinations by tax authorities for years prior to2012.  Income taxes are generally allocated to each company

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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 months endedMarch 31, 2017.  

Earnings Per Share

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

	Three Months Ended March 31,
(In millions except per share data)	2017		2016
Net income	$	36.0	$	25.2
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.3		—
Diluted average common shares outstanding	200.0		199.7
Basic Earnings Per Average Common Share	$	0.18	$	0.13
Diluted Earnings Per Average Common Share	$	0.18	$	0.13
Anti-dilutive shares excluded from earnings per share calculation	—		—

8. Long-Term Debt

AtMarch 31, 2017, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

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

SERIES			DATE DUE	AMOUNT
				(In millions)
0.65%	-	0.95%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.65%	-	0.90%	Muskogee Industrial Authority, January 1, 2025	32.4
0.66%	-	0.95%	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

17

remarketing agent is unable to remarket any such bonds, OG&E is obligated to repurchase such unremarketed bonds.  As OG&E has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as long-term debt in the Company's Condensed Consolidated Financial Statements. OG&E believes that it has sufficient liquidity to meet these obligations.

Issuance of New Long-Term Debt

In March 2017, OG&E issued $300.0 millionof 4.15 percentsenior notes dueApril 1, 2047. The proceeds from the issuance were used to repay short-term debt and were added to OG&E's general funds to be used for general corporate purposes, including to repay borrowings under the revolving credit facility, to fund the payment at maturity of OG&E's$125.0 millionof 6.5 percentsenior notes due July 15, 2017, and to fund ongoing capital expenditures and working capital.

Expected Issuance of Long-Term Debt

OG&E expects to issue up to$300.0 millionof long-term debt during the second half of 2017, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.

9. Short-Term Debt and CreditFacilities

On March 8, 2017 the Company and OG&E each entered into new $450.0 million unsecured five-year revolving credit facilities to replace existing facilities. Each of these new facilities is scheduled to terminate on March 8, 2022. However, the Company and OG&E have the right to request an extension of the revolving credit facility termination date under their respective facility for an additional one-year period, which can be exercised up to two times. All such extension requests are subject to majority lender group approval (and only the commitments of those lenders that consent to such extension (or that agree to replace any non-consenting lender) will be extended for such additional period).

Borrowings under the new facilities bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.69 percent to 1.275 percent, or an alternate base rate, plus a margin of 0.0 percent to 0.275 percent. The new facilities have a facility fee that ranges from 0.06 percent to 0.225 percent. Interest rate margins and facility fees are based on the Company's and OG&E's then-current senior unsecured credit ratings, as applicable.

Each of the facilities provides for issuance of letters of credit, provided that (i) the aggregate outstanding credit exposure shall not exceed the amount of the revolving credit facility and (ii) the aggregate outstanding stated amount of letters of credit issued under such facility shall not exceed a specified maximum sublimit ($100 million for each of the Company and OG&E). Advances under the facilities may be used to refinance existing indebtedness and for working capital and general corporate purposes of the respective borrower and its subsidiaries, including commercial paper liquidity support, letters of credit, acquisitions and distributions.

Each of the facilities is unsecured and, under certain circumstances, may be increased (by up to $150 million in each case for the Company and OG&E), to a maximum revolving commitment limit of $600 million. Advances of revolving loans and letters of credit under the facilities are subject to certain conditions precedent, including the accuracy of certain representations and warranties and the absence of any default or unmatured default.

The Company and OG&E's facilities each has a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E's facilities each also contains covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million, and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

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As ofMarch 31, 2017, the Company had$128.2 millionof short-term debt as compared to$236.2 million at December 31, 2016. The following table provides information regarding the Company's revolving credit agreements at March 31, 2017.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	128.2	1.219	%	(D)	March 8, 2022
OG&E (C)	450.0		1.8		0.95	%	(D)	March 8, 2022
Total	$	900.0	$	130.0	1.214	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2017.

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

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

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

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions.Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations.Any future 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, 2017 and ending December 31, 2018.

10. Retirement Plans and Postretirement Benefit Plans

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

Net Periodic Benefit Cost

	Pension Plan						Restoration of Retirement Income Plan				Postretirement Benefit Plans
	Three Months Ended						Three Months Ended				Three Months Ended
	March 31,						March 31,				March 31,
(In millions)	2017 (B)			2016 (B)			2017 (B)		2016 (B)		2017 (B)			2016 (B)
Service cost	$	4.2		$	4.4		$	0.1	$	0.1	$	0.2		$	0.3
Interest cost	6.5			6.6			0.1		0.1		2.2			2.3
Expected return on plan assets	(10.7		)	(10.5		)	—		—		(0.6		)	(0.6		)
Amortization of net loss	4.0			4.2			0.1		0.2		0.6			0.5
Amortization of unrecognized prior service cost (A)	—			—			—		—		—			(2.2		)
Total net periodic benefit cost	4.0			4.7			0.3		0.4		2.4			0.3
Less: Amount paid by unconsolidated affiliates	0.8			1.3			—		—		0.4			0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.2		$	3.4		$	0.3	$	0.4	$	2.0		$	0.2

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(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$5.5 millionand$4.0 millionof net periodic benefit cost recognizedduring thethree months endedMarch 31, 2017and2016, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedMarch 31, 2017 and 2016of$2.9 millionand$2.3 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1); and

• an increase in postretirement medical expense in the three months endedMarch 31, 2017 and 2016 of $1.1 million and $2.0 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 for regulatory liability (see Note 1).

	Three Months Ended
	March 31,
(In millions)	2017		2016
Capitalized portion of net periodic pension benefit cost	$	1.0	$	1.2
Capitalized portion of net periodic postretirement benefit cost	0.7		0.1

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.

The following tables summarize the results of the Company's business segments during the three months endedMarch 31, 2017 and 2016.

Three Months Ended March 31, 2017	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	456.0	$	—		$	—		$	—		$	456.0
Cost of sales	208.7		—			—			—			208.7
Other operation and maintenance	126.1		0.1			(2.2		)	—			124.0
Depreciation and amortization	54.7		—			0.9			—			55.6
Taxes other than income	22.3		0.2			1.4			—			23.9
Operating income (loss)	44.2		(0.3		)	(0.1		)	—			43.8
Equity in earnings of unconsolidated affiliates	—		35.6			—			—			35.6
Other income (expense)	12.9		0.1			(1.3		)	(0.1		)	11.6
Interest expense	33.6		—			1.5			(0.1		)	35.0
Income tax expense (benefit)	7.3		15.4			(2.7		)	—			20.0
Net income (loss)	$	16.2	$	20.0		$	(0.2	)	$	—		$	36.0
Investment in unconsolidated affiliates	$	—	$	1,158.9		$	—		$	—		$	1,158.9
Total assets	$	8,950.9	$	1,521.2		$	91.1		$	(428.3	)	$	10,134.9

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

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 Notes13and14 to the Company's Consolidated Financial Statements included in the Company's 2016Form 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. Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to 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.

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2.  OG&E entered into an agreement on February 9, 2015, to install the Dry Scrubber systems.  The Dry Scrubbers are scheduled to be completed by 2019. More detail regarding the ECP can be found under “Pending Regulatory Matters” in Note 13.

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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.

13. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note14to the Company's Consolidated Financial Statements included in the Company's 2016Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Oklahoma Rate Case Filing

On December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 millionand a10.25 percent return on equity based on a common equity percentage of 53 percent. The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billionof electric infrastructure additions since its last general rate case in Oklahoma.

On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million, subject to refund for amounts in excess of the rates approved by the OCC. As of March 31, 2017 OG&E has fully reserved all of the interim rate increase pending resolution of the refund methodology.

In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations included, among other things, the use of OG&E's actual capital structure of53.0 percent equity and47.0 percentlong-term debt and a return on equity of 9.87 percentresulting in an annual increase in OG&E's revenues of $40.7 million.

On March 20, 2017, the OCC held hearings and issued a final order. The final order results in an annual net increase of approximately$8.8 millionin OG&E's rates to its Oklahoma retail customers. Although the final order adopted certain of the recommendations set forth in the ALJ Report, it differs in certain key respects.

The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent, (ii) depreciation expense is reduced by approximately$28.6 millionfrom the ALJ report or $36.4 millionfrom current rates on an annual basis, (iii) recovery of only 50.0 percent of short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause.

As a result of the final order, OG&E recorded in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities, and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates.

Pending Regulatory Matters

Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked

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the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 400 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs.

On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates.On April 28, 2016, the OCC approved the Dry Scrubber project.

Two parties appealed the OCC's decision to the Oklahoma Supreme Court. The Company is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.

OG&E anticipates the total cost of Dry Scrubbers will be $547.5 million, including allowance for funds used during construction and capitalized ad valorem taxes. As of March 31, 2017, OG&E had invested$281.6 millionof construction work in progress on the Dry Scrubbers.OG&E anticipates the total cost for the Mustang Modernization Plan will be$424.9 million, including allowance for funds used during construction and capitalized ad valorem taxes, and expects the project to be completed in late 2017. As ofMarch 31, 2017, OG&E had invested $231.8 millionon the Mustang Modernization Plan.

Integrated Resource Plans

In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Arkansas by October 1, 2017 and in Oklahoma by October 1, 2018.

Arkansas Rate Case Filing

On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 millionrate increase based on a 10.25 percentreturn on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over$3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management, and increased recovery of depreciation and dismantlement costs.

In April 2017, OG&E entered into a settlement with the staff of the APSC and other intervenors. The settlement provides for a $7.1 millionannual rate increase and a9.5 percentreturn on equity on a50.0 percentequity capital structure. The settlement is subject to approval of the APSC. Hearings are scheduled for the APSC to review the settlement on May 2, 2017. OG&E expects to receive an order from the APSC in the second quarter of 2017.

The settlement also provides that OG&E will be regulated under a formula rate rider, which should result in a more efficient process as the return on equity, depreciation rates and capital structure should not change from what is approved by the APSC in the current rate case proceeding unless differences of plus or minus 50 basis points in return on equity were to occur. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC. OG&E expects to make its first filing under the Arkansas Formula Rate Rider in October 2018.

Fuel Adjustment Clause Review for Calendar Year 2015

On September 8, 2016, the OCC staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. At a hearing on March 30, 2017, the PUD staff recommended to the OCC that the 2015 fuel costs be found prudent. The Company expects to receive an OCC order in the second quarter of 2017.

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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. As disclosed in the Company's 2016 Form 10-K, Enable is subject to a number of risks, including contract renewal risk, the reliance on the drilling and production decisions of others and the volatility of natural gas, NGL and crude oil prices. If any of those risks were to occur, the Company's business, financial condition, results of operations or cash flows could be materially adversely affected.

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 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 utilizes cash distributions from its investment in Enable to help 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.

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Summary of Operating Results

Three Months Ended March 31, 2017as Compared toThree Months Ended March 31, 2016

Net income was$36.0 million, or$0.18per diluted share, during thethree months endedMarch 31, 2017as compared to$25.2 million, or$0.13per diluted share, during the same period in2016. Theincreasein net income of$10.8 million, or$0.05 per diluted share, during thethree months endedMarch 31, 2017as compared to the same period in2016was primarily due to:

• an increase in net income at OG&E of$10.1 million, or $0.05 per diluted share of the Company's common stock, primarily due to lower depreciation expense related to the reduction in depreciation rates approved in the OCC's final order, as discussed in Note 13, and higher other income related to increased allowance for equity funds used during construction. These increases were partially offset by an increase in other operation and maintenance expense, a decrease in gross margin and higher income tax expense; and

• an increase in net income at OGE Holdings of $2.0 million, or $0.01 per diluted share of the Company's common stock, primarily due to an increase of equity in earnings of Enable partially offset by an increase in income tax expense; partially offset by

• a decrease in net income at OGE Energy of $1.3 million, or $0.01 per diluted share of the Company's common stock, primarily due to an increase in other expenses associated with the deferred compensation plan and an increase in interest expense related to higher commercial paper borrowings.

Recent Developments and Regulatory Matters

As discussed in Note 13, on March 20, 2017, the OCC issued a final order in OG&E's general rate case. The final order results in an annual net increase of approximately $8.8 millionin OG&E's rates to its Oklahoma retail customers. Although the final order adopted certain of the recommendations set forth in the ALJ Report, it differs in certain key respects.

The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent, (ii) depreciation expense is reduced by approximately$28.6 millionfrom the ALJ report or$36.4 million from current rates on an annual basis, (iii) recovery of only50.0 percentof short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause.

As a result of the final order, OG&E recorded in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities, and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates.

2017 Outlook

OG&E

The Company projects OG&E earnings to be at the low end of the earnings range of $316.0 million to $340.0 million of net income, or $1.58 to $1.70 per average diluted share in 2017 based on the OCC rate order and the following assumptions:

• normal weather patterns are experienced for the remainder of the year;

• new rates take effect in Oklahoma May 1, 2017;

• new rates take effect in Arkansas in 2017;

• gross margin on revenues of approximately $1.405 billion to $1.420 billion based on sales growth of approximately 1 percent on a weather adjusted basis;

• approximately $110 million of gross margin is primarily attributed to regionally allocated transmission projects;

• operating expenses of approximately $844 million to $865 million with operation and maintenance expenses approximately 57 percent of the total;

• interest expense of approximately $144 million which assumes a $16 million allowance for borrowed funds used during construction reduction to interest expense and includes the debt issuance of $300 million on March 31, 2017;

• other income of approximately $62 million including approximately $35 million of allowance for equity funds used during construction;

• an effective tax rate of approximately 31 percent; and

• assumes $21 million of pre-tax net income or $0.06 per average diluted share for rates implemented on July 1, 2016 through December 31, 2016 based on the rate order received for the Oklahoma General Rate Case.

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OG&E has significant seasonality in its earnings. OG&E typically shows minimal earnings in the first and fourth quarters with a majority of earnings in the third quarter due to the seasonal nature of air conditioning demand.

OGE Enogex Holdings LLC

The Company projects the earnings contribution from its ownership interest in Enable Midstream to be approximately $70 million to $78 million of $0.35 to $0.39 per average diluted share and receive approximately $140 million in cash distributions.

Consolidated OGE

The Company projects 2017 earnings guidance to be at the lower end of the earnings range of $386 million to $418 million of net income, or $1.93 to $2.09 per average diluted share and is based on the following assumptions:

• approximately 200 million average diluted shares outstanding; and

• an effective tax rate of approximately 33 percent.

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.

Detailed below is a reconciliation of gross margin to revenue included in the 2017 Outlook.

Reconciliation of Gross Margin to Revenue
Year Ended December 31, (Dollars in Millions)	2017
Operating revenues	$	2,096
Cost of sales	691
Gross margin	$	1,405

Enable's Non-GAAP Financial Measures

Gross margin is defined by Enable as total revenues minus costs of natural gas and NGLs, excluding depreciation and amortization. Total revenues consist of the fees that they charge their customers and the sales price of natural gas and NGLs that they sell. The cost of natural gas and NGLs consists of the purchase price of natural gas and NGLs that they purchase. Enable deducts the cost of natural gas and NGLs from total revenue to arrive at a measure of the core profitability of their mix of fee-based and commodity-based customer arrangements. Gross margin allows for meaningful comparison of the operating results between Enable's fee-based revenues and Enable's commodity-based contracts which involve the purchase or sale of natural gas, NGLs and/or crude oil. In addition, the Company believes gross margin allows for a meaningful comparison of the results of Enable's commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold.

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Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for thethree months endedMarch 31, 2017as compared to the same period in2016and the Company's consolidated financial position atMarch 31, 2017. Due to seasonal fluctuations and other factors, the Company'soperating results for thethree months endedMarch 31, 2017are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2017or 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
	March 31,
(In millions except per share data)	2017		2016
Net income	$	36.0	$	25.2
Basic average common shares outstanding	199.7		199.7
Diluted average common shares outstanding	200.0		199.7
Basic earnings per average common share	$	0.18	$	0.13
Diluted earnings per average common share	$	0.18	$	0.13
Dividends declared per common share	$	0.30250	$	0.27500

Results by Business Segment

	Three Months Ended
	March 31,
(In millions)	2017			2016
Net income (loss)
OG&E (Electric Utility)	$	16.2		$	6.1
OGE Holdings (Natural Gas Midstream Operations)	20.0			18.0
Other Operations (A)	(0.2		)	1.1
Consolidated net income	$	36.0		$	25.2

(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
	March 31,
(Dollars in millions)	2017			2016
Operating revenues	$	456.0		$	433.1
Cost of sales	208.7			177.9
Other operation and maintenance	126.1			116.3
Depreciation and amortization	54.7			76.7
Taxes other than income	22.3			23.6
Operating income	44.2			38.6
Allowance for equity funds used during construction	6.9			1.6
Other income	6.4			4.0
Other expense	0.4			0.3
Interest expense	33.6			35.5
Income tax expense	7.3			2.3
Net income	$	16.2		$	6.1
Operating revenues by classification
Residential	$	192.3		$	178.5
Commercial	124.3			102.7
Industrial	44.3			38.2
Oilfield	38.1			32.3
Public authorities and street light	44.5			36.1
Sales for resale	—			0.1
System sales revenues	443.5			387.9
Provision for rate refund	(20.8		)	—
Integrated market	(3.5		)	9.1
Other	36.8			36.1
Total operating revenues	$	456.0		$	433.1
Reconciliation of gross margin to revenue:
Operating revenues	$	456.0		$	433.1
Cost of sales	208.7			177.9
Gross margin	$	247.3		$	255.2
MWH sales by classification (In millions)
Residential	2.0			2.1
Commercial	1.6			1.6
Industrial	0.8			0.9
Oilfield	0.8			0.8
Public authorities and street light	0.7			0.7
System sales	5.9			6.1
Integrated market	0.3			0.4
Total sales	6.2			6.5
Number of customers	836,099			827,685
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	2.817			2.038
Coal	2.110			2.288
Total fuel	2.135			1.945
Total fuel and purchased power	3.132			2.611
Degree days (A)
Heating - Actual	1,381			1,552
Heating - Normal	1,799			1,798
Cooling - Actual	57			12
Cooling - Normal	13			13

(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 March 31, 2017as Compared toThree Months Ended March 31, 2016

OG&E's net incomeincreased$10.1 million, during thethree months endedMarch 31, 2017as compared to the same period in2016primarily due to lower depreciation and amortization expense as a result of the OCC's final order mandating a reduction in depreciation rates as discussed in Note 13 and higher other income partially offset by higher other operation and maintenance expense, lower gross margin and higher income tax expense.

Operating revenues were$456.0 millionduring thethree months endedMarch 31, 2017as compared to$433.1 millionduring the same period in2016, an increaseof$22.9 million, or5.3 percent. Cost of sales were$208.7 millionduring thethree months endedMarch 31, 2017as compared to$177.9 millionduring the same period in2016, an increaseof$30.8 million, or17.3 percent. Gross margin was$247.3 millionduring thethree months endedMarch 31, 2017as compared to$255.2 millionduring the same period in2016, a decreaseof$7.9 million, or3.1 percent. The below factors contributed to the change in gross margin:

(In millions)	Change
Reserve for rate refund (A)	$	(20.8	)
Interim rate increase - Oklahoma (A)	15.4
Weather (price and quantity) (B)	(4.9		)
Price variance	(1.6		)
Other	1.9
New customer growth	2.1
Change in gross margin	$	(7.9	)

(A) On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million. On March 20, 2017, the OCC issued a final order resulting in an increase of $8.8 million, as discussed in Note 13. The interim rate increase is fully reserved as ofMarch 31, 2017.

(B) Heating degree days decreased approximately 11 percent.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Cost of sales was$208.7 millionduring the three months endedMarch 31, 2017as compared to$177.9 millionduring the same period in 2016, an increase of $30.8 million, or 17.3 percent. OG&E's change in cost of sales for the three months endedMarch 31, 2017as compared to the same period in 2016are detailed in the table below.

(In millions)	Change
Fuel expense (A)	$	13.4
Purchased power costs
Purchases from SPP (B)	17.3
Wind	0.7
Cogeneration	(5.6		)
Transmission expense (C)	5.0
Change in cost of sales	$	30.8

(A) Increase in fuel expense was primarily due to increased utilization of company owned generation.

(B) The cost of purchases from the SPP increased despite a 13 percent reduction in MWhs purchased. The cost per MWh increased 44 percent, due primarily to higher gas prices.

(C) Increase in transmission related charges was 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 and the APSC.

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Operating Expenses

Other operation and maintenance expense was$126.1 millionduring thethree months endedMarch 31, 2017as compared to$116.3 millionduring the same period in2016, an increaseof$9.8 million, or8.4 percent. The below factors contributed to the change in other operation and maintenance expense:

(In millions)	Change
Marketing (related to demand side management)	$	2.8
Payroll & benefits (A)	2.6
Corporate allocations and overheads	2.0
Contract professional services (B)	1.6
Maintenance at power plants	1.0
Other	(0.2		)
Change in other operation and maintenance expense	$	9.8

(A) Increased primarily due to increased 401k match due to higher incentive payout, increased annual salaries, overtime and active medical and dental expenses.

(B) Increased primarily due to increased consulting costs associated with demand side management programs.

Depreciation and amortization expense was$54.7 millionduring thethree months endedMarch 31, 2017as compared to$76.7 millionduring the same period in2016, a decreaseof$22.0 million, or28.7 percent, primarily due to lower depreciation expense related to the reduction in depreciation rates approved in the OCC's final order as discussed in Note 13 partially offset by additional assets being placed into service.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was$6.9 millionduring thethree months endedMarch 31, 2017as compared to$1.6 millionduring the same period in2016, an increase of $5.3 million, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other Income.Other income was $6.4 million during the three months endedMarch 31, 2017 as compared to $4.0 million during the same period in 2016, an increase of $2.4 million, or 60.0 percent, primarily due to an increase in the tax gross up related to higher allowance for funds used during construction partially offset by lower guaranteed flat bill margins.

Income Tax Expense.Income tax expense was$7.3 millionduring thethree months endedMarch 31, 2017as compared to$2.3 millionduring the same period in2016, an increaseof$5.0 million, primarily due to higher pre-tax income.

OGE Holdings (Natural Gas Midstream Operations)

	Three Months Ended March 31,
(In millions)	2017			2016
Operating revenues	$	—		$	—
Cost of sales	—			—
Other operation and maintenance	0.1			0.2
Depreciation and amortization	—			—
Taxes other than income	0.2			—
Operating income (loss)	(0.3		)	(0.2		)
Equity in earnings of unconsolidated affiliates	35.6			28.3
Other income	0.1			—
Income before taxes	35.4			28.1
Income tax expense	15.4			10.1
Net income attributable to OGE Holdings	$	20.0		$	18.0

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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 months endedMarch 31, 2017 as compared to the same period in 2016:

	Three Months Ended
	March 31,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2017			2016
(In millions)
Enable net income	$	110.8		$	86.0
Differences due to timing of OGE Energy and Enable accounting close	—			(11.7		)
Enable net income used to calculate OGE Energy's equity in earnings	$	110.8		$	74.3
OGE Energy’s percent ownership at period end	25.7		%	26.3		%
OGE Energy’s portion of Enable net income	$	28.5		$	19.5
Impairments recognized by Enable associated with OGE Energy’s basis differences	—			1.8
OGE Energy's share of Enable net income	$	28.5		$	21.3
Amortization of basis difference	2.8			2.9
Elimination of Enable fair value step up	4.3			4.1
Equity in earnings of unconsolidated affiliates	$	35.6		$	28.3

Equity in earnings of unconsolidated affiliates includes the Company's share of Enable earnings adjusted for the amortization of the basis difference of the Company's investment in Enogex and its underlying equity in the net assets of Enable and is also adjusted for the elimination of the Enogex Holdings fair value adjustments.

The difference between OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $736.6 million as of March 31, 2017. The basis difference is being amortized over approximately 30 years, beginning in May 2013. The following table reconciles the basis difference in Enable from December 31, 2016 to March 31, 2017.

(In millions)
Basis difference as of December 31, 2016	$	743.7
Amortization of basis difference	(2.8		)
Elimination of Enable fair value step up	(4.3		)
Basis difference as of March 31, 2017	$	736.6

Enable Results of Operations

The following table represents summarized financial information of Enable for the three months endedMarch 31, 2017 as compared to the same period in 2016:

	Three Months Ended
	March 31,
(In millions)	2017		2016
Operating revenues	$	666	$	509
Cost of natural gas and natural gas liquids	308		195
Operating income	140		103
Net income	111		86

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Enable Operating Data

The following table presents Enable's operating data for the three months endedMarch 31, 2017 as compared to the same period in 2016:

	Three Months Ended
	March 31,
	2017	2016
Gathered volumes - TBtu/d	3.29	3.05
Transportation volumes - TBtu/d	5.48	5.11
Natural gas processed volumes - TBtu/d	1.87	1.78
NGLs sold - million gallons/d (A)(B)	78.65	76.31

(A) Excludes condensate.

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

Three Months Ended March 31, 2017as Compared toThree Months Ended March 31, 2016

OGE Holding's earnings before taxes increased$7.3 million for the three months endedMarch 31, 2017 as compared to the same period in 2016, primarily due to an increase in equity in earnings of Enable of $7.3 million. This increase in the Company's equity in earnings of Enable was attributable primarily to an increase in Enable's operating income, which increased $37.0 million during the three months endedMarch 31, 2017 as compared to the same period in 2016 primarily due to an increase in Enable's gross margin of $44.0 million that increased the Company's equity in earnings of Enable by $11.3 million partially offset by an increase in depreciation and amortization expense of $7.0 million that decreased the Company's equity in earnings of Enable by $1.8 million. The equity in earnings of Enable was also decreased by preferred unit distributions of $9.0 million that decreased the Company's equity in earnings of Enable by $2.3 million.

Enable's gathering and processing business segment reported an increase in operating income of $34.0 million. This increase in operating income was primarily due to an increase in gross margin of $37.0 million that increased the Company's equity in earnings of Enable by $9.5 million and a decrease in operations and maintenance and general and administrative expense of $5.0 million that increased the Company's equity in earnings of Enable by $1.3 million. Partially offsetting the impact of increased gross margin and decreased operations and maintenance and general and administrative expense, there was an increase of depreciation and amortization of $7.0 million that decreased the Company's equity in earnings of Enable by $1.8 million and an increase in taxes other than income of $1.0 million that decreased the Company's equity in earnings of Enable by $0.3 million. Gathering and processing gross margin increased primarily due to an increase in gathered volumes in the Anadarko and Ark-La-Tex Basins, increases in gross margin from changes in the fair value of condensate and NGL derivatives, increased processing margins resulting from higher average NGL prices and higher processed volumes in the Anadarko Basin offset by lower processed volumes in the Ark-La-Tex Basin, increases in natural gas sales due to higher average natural gas prices and an increase in the Williston Basin due to increased water transportation services. These increases were partially offset by a decrease associated with the annual fuel rate determination in 2016.

Enable's transportation and storage business segment reported an increase in operating income of $3.0 million. This increase in operating income was primarily due to an increase in gross margin of $7.0 million that increased the Company's equity in earnings of Enable by $1.8 million, partially offset by an increase in operations and maintenance and general and administrative expense of $4.0 million that decreased the Company's equity in earnings of Enable by $1.0 million. Transportation and storage gross margin increased primarily due to an increase in gross margin from changes in the fair value of natural gas derivatives, an increase in transportation margins and an increase in NGL sales due to an increase in prices. These increases were partially offset by a decrease in system management activities and a decrease in margins on transportation services for local distribution companies.

Income tax expense was $15.4 million during the three months endedMarch 31, 2017 as compared to $10.1 million during the same period in 2016, an increase of $5.3 million primarily due to higher pretax operating income and a remeasurement of state deferred taxes related to the Company's investment in Enable during the three months endedMarch 31, 2016.

Off-Balance Sheet Arrangements

There have been no significant changes in the Company's off-balance sheet arrangements from those discussed in the Company's 2016Form 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.

Accounts Receivable and Accrued Unbilled Revenues.The balance of Accounts Receivable and Accrued Unbilled Revenues was$198.6 millionand$235.2 millionatMarch 31, 2017andDecember 31, 2016, respectively,a decreaseof$36.6 million, or15.6 percent, primarily due toa decrease in billings to OG&E's retail customers reflecting lower usage due to milder weather in March 2017 as compared to December 2016.

Income Taxes Receivable. The balance of Income Taxes Receivable was $13.4 million and $19.4 million at March 31, 2017 and December 31, 2016, respectively, a decrease of $6.0 million, or 30.9 percent, primarily due to Oklahoma state tax refund of approximately $5.8 million in February 2017.

Fuel Clause Under Recoveries. The balance of Fuel Clause Under Recoveries was $73.4 million and $51.3 million at March 31, 2017 and December 31, 2016, respectively, an increase of $22.1 million, or 43.1 percent, primarily due to lower recoveries from OG&E retail customers as compared to the actual cost of fuel and purchased power.

Short-Term Debt. The balance of Short-term Debt was $128.2 million and $236.2 million at March 31, 2017 and December 31, 2016, respectively, a decrease of $108.0 million, or 45.7 percent, due to the repayment of short-term debt from the proceeds of the senior note issuance in March 2017.

Accounts Payable. The balance of Accounts Payable was $244.3 million and $205.4 million at March 31, 2017 and December 31, 2016, respectively, an increase of $38.9 million, or 18.9 percent, primarily due to the timing of vendor payments.

Accrued Taxes. The balance of Accrued Taxes was $25.2 million and $41.3 million at March 31, 2017 and December 31, 2016, respectively, a decrease of $16.1 million, or 39.0 percent, primarily resulting from ad valorem payments of approximately $36.7 million offset by tax accruals of approximately $20.0 million.

Accrued Interest. The balance of Accrued Interest was $33.0 million and $40.4 million at March 31, 2017 and December 31, 2016, respectively, a decrease of $7.4 million, or 18.3 percent, primarily due to payments of interest on long-term debt of $42.4 million offset by accruals of $35.0 million.

Accrued Compensation. The balance of Accrued Compensation was $25.5 million and $45.1 million at March 31, 2017 and December 31, 2016, respectively, a decrease of $19.6 million, or 43.5 percent, primarily due to the payment of 2016 incentive compensation in March 2017 partially offset by 2017 accruals.

Cash Flows

	Three Months Ended
	March 31,						2017 vs. 2016
(In millions)	2017			2016			$ Change			% Change
Net cash provided from operating activities	$	91.0		$	73.4		$	17.6		24.0	%
Net cash used in investing activities	(219.9		)	(171.1		)	(48.8		)	28.5	%
Net cash provided from financing activities	128.6			22.5			106.1			*

* Change is greater than 100 percent variance.

Operating Activities

Theincrease of $17.6 million, or 24.0 percent, in net cash provided from operating activities during thethree months endedMarch 31, 2017as compared to the same period in2016was primarily due to a decrease in vendor payments and higher receipts from customers at OG&E partially offset by lower fuel recoveries and higher tax payments.

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Investing Activities

Theincrease of $48.8 million, or 28.5 percent, in net cashused ininvesting activities during thethree months endedMarch 31, 2017as compared to the same period in2016was primarily due toan increase in capital expenditures related to environmental projects at OG&E.

Financing Activities

Theincrease of $106.1 millionin net cash provided from financing activitiesduring thethree months endedMarch 31, 2017as compared to the same period in2016was primarily due to the issuance of $300.0 million in long-term debt at OG&E in March 2017 and the payment of long-term debt at OG&E in January 2016 partially offset by a decrease in short-term debt.

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 2017 through 2021 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)	2017		2018		2019		2020		2021
OG&E Base Transmission	$	35	$	30	$	30	$	30	$	30
OG&E Base Distribution	195		175		175		175		175
OG&E Base Generation	40		75		75		75		75
OG&E Other	35		25		25		25		25
Total Base Transmission, Distribution, Generation and Other	305		305		305		305		305
OG&E Known and Committed Non-Base Projects:
Transmission Projects:
Other Regionally Allocated Projects (A)	50		20		20		20		20
Large SPP Integrated Transmission Projects (B) (C)	155		20		—		—		—
Total Transmission Projects	205		40		20		20		20
Other Projects:
Solar	20		—		—		—		—
Environmental - low NOX burners (D)	15		—		—		—		—
Environmental - Dry Scrubbers (D)	160		95		15		—		—
Combustion turbines - Mustang	150		55		—		—		—
Environmental - natural gas conversion (D)	20		25		25		—		—
Allowance of funds used during construction and ad valorem taxes	55		40		5		—		—
Total Other Projects	420		215		45		—		—
Total Known and Committed Non-Base Projects	625		255		65		20		20
Total	$	930	$	560	$	370	$	325	$	325

(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.

34

(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. $5.0 million of the estimated cost has been spent prior to 2017.	$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 and construction of the Mathewson substation on this transmission line. $50.0 million of the estimated cost associated with the Mathewson to Cimarron line and substations went into service in 2016; $55.0 million has been spent prior to 2017.	$180	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 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 on the Company's financial objectives.

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.

Short-Term Debt and CreditFacilities

Short-term borrowings generally are used to meet working capital requirements. On March 8, 2017, the Company and OG&E entered into new revolving credit facilities totaling in the aggregate $900.0 million. These bank facilities can also be used asletter of credit facilities.  As ofMarch 31, 2017, the Company had$128.2 millionof short-term debt as compared to$236.2 million at December 31, 2016. The average balance of short-term debt during the three months endedMarch 31, 2017 was $212.6 million at a weighted-average interest rate of 0.99 percent. The maximum month-end balance of short-term debt during the three months endedMarch 31, 2017 was $234.5 million. AtMarch 31, 2017, there were$1.8 millionsupporting letters of credit at a weighted-average interest rate of0.95 percent. At March 31, 2017, the Company had $770.0 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, 2017 and ending December 31, 2018.   At March 31, 2017, the Company had no balance in cash and cash equivalents.  See Note9for a discussion of the Company's short-term debt activity.

Issuance of New Long-Term Debt

In March 2017, OG&E issued $300.0 millionof 4.15 percentsenior notes dueApril 1, 2047. The proceeds from the issuance were used to repay short-term debt and were added to OG&E's general funds to be used for general corporate purposes,

35

including to repay borrowings under the revolving credit facility, to fund the payment at maturity of OG&E's$125.0 millionof 6.5 percentsenior notes due July 15, 2017, and to fund ongoing capital expenditures and working capital.

Expected Issuance of Long-Term Debt

OG&E expects to issue up to $300.0 million of long-term debt during the second half of 2017, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.

Quarterly Distributions by Enable

Pursuant to the Enable Limited Partnership Agreement, during the three months endedMarch 31, 2017 Enable made distributions of $35.3 million to the Company.

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 Company's 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 2016Form 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 for a discussion of the Company's commitments and contingencies.

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 2016Form 10-K.

36

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 December 28, 2011, the EPA issued a final Regional Haze Rule for Oklahoma which adopted a FIP for SO₂ emissions at Sooner Units 1 and 2 and Muskogee Units 4 and 5. The FIP compliance date is now January 4, 2019 as a result of the appeal filed by OG&E and others.

OG&E's current strategy for satisfying the FIP includes installing Dry Scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. As described in Note 13, the OCC has approved the Company's decision to install Dry Scrubbers at the Sooner Units. As of March 31, 2017, OG&E has incurred $281.6 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. Litigation challenging the rule prevented it from entering into effect until 2014. Several parties to that litigation, including OG&E, have petitions for review that remain pending although the rule is now effective. Compliance with the CSAPR began in 2015 using the amount of allowances originally scheduled to be available in 2012. As of March 31, 2017, OG&E has installed six low NO_X burner systems on two Muskogee units, two Sooner units and two Seminole units and is in compliance. Installation of the final low NO_X burner system is scheduled during the second quarter of 2017 on the remaining Seminole unit.

On September 7, 2016, the EPA finalized an update to the 2011 CSAPR. The new rule applies to ozone-season NO_X in 22 eastern states (including Oklahoma), utilizes a cap and trade program for NO_X emissions and will take effect on May 1, 2017. The rule reduces the 2016 CSAPR emissions cap for all seven of OG&E's coal and gas facilities by 47 percent combined. On December 23, 2016, OG&E filed a petition for reconsideration of the 2016 rule with the EPA. OG&E is asking the agency to reconsider the methodology used to calculate state ozone-season emissions budgets. OG&E's petition, along with the petitions for reconsideration filed by various other parties, is currently pending. Also on December 23, 2016, OG&E filed a petition for review of the 2016 rule in the United States Court of Appeals for the District of Columbia Circuit, asking the court to set aside the rule on the grounds that it is arbitrary, capricious, an abuse of the EPA's discretion and not otherwise in accordance with the law. OG&E's case has been consolidated with several other petitions for review, all of which are currently pending.

Due to pending litigation and administrative proceedings, the ultimate timing and impact of the 2016 CSAPR update rule on our operations cannot be determined with certainty at this time. However, the Company does not expect that the reduced emissions cap, if upheld, will have a material impact on the Company's financial position, results of operations or cash flows.

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 Company believes that it complied with the MATS rule by the April 16, 2016 deadline that applied to OG&E. Nonetheless, there is continuing litigation, to which the Company is not a party, challenging whether the EPA had statutory authority to issue the MATS rule.

37

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 March 31, 2017, 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.

The EPA proposed to designate part of Muskogee County in which OG&E's Muskogee Power Plant is location, as non -attainment for the 2010 SO₂ NAAQS on March 1, 2016, even though nearby monitors indicate compliance with the NAAQS. The proposed designation is based on modeling that does not reflect the planned conversion of two of the coal units at Muskogee to natural gas. OG&E commented that the EPA should defer a designation of the area to allow time for additional monitoring. The EPA has a deadline for making a decision on the designation pursuant to a consent decree entered by the U.S. District Court for the Northern District of California to resolve a citizen suit. The deadline has been extended several times, with the current deadline being April 28, 2017. The EPA has published final decisions on all other areas of Oklahoma. In this decision, Noble County, in which the Sooner plant is located, was deemed to be in attainment with the 2010 standard. At this time, OG&E cannot determine with any certainty whether any of these determinations will cause a material impact to the Company's financial results.

On September 30, 2015 the EPA finalized a NAAQS for ozone at 70 ppb, which is more stringent than the previous standard of 75 ppb, set in 2008. In September 2016, Governor Mary Fallin submitted to the EPA the recommendation of "attainment/unclassifiable" for all 77 counties in Oklahoma. This recommendation is subject to approval by the EPA.

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.

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.

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. Several states outside the area where the Company operates 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.

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 proposed 43 percent reduction to 32 percent in the final rule. The mass-based approach for existing units calls for a 24 percent reduction by 2030 in Oklahoma.

A number of states, including Oklahoma, filed lawsuits against the Clean Power Plan. On February 9, 2016, the U.S. Supreme Court issued orders staying implementation of the Clean Power Plan pending resolution of challenges to the rule. The Company is unable to determine what impact the lawsuits will ultimately have on the Clean Power Plan or what impact the stay in implementation will have; however, if the Clean Power Plan survives judicial review and is implemented as written, it could result in significant additional compliance costs that would affect our future consolidated financial position, results of operations

38

and cash flows if such costs are not recovered through regulated rates. Due to 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.

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's plan to comply with the EPA’s MATS and Regional Haze Rule FIP includes 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 SIPs 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 submitted a SIP revision for the EPA's approval on November 7, 2016 to comply with this rule. 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. On September 8, 2016, WildEarth Guardians, Defenders of Wildlife and the Center for Biological Diversity filed a petition with the U.S. Fish and Wildlife Services to list the lesser prairie chicken as "endangered" under the Endangered Species Act. On November 30, 2016, the U.S. Fish and Wildlife Services published a notice in the Federal Register announcing its finding that the September 2016 petition presents information indicating that listing of the lesser prairie-chicken may be warranted. The agency has initiated a 12-month status review. OG&E will continue to monitor the progress of the petition.

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2.  OG&E entered into an agreement on February 9, 2015, to install the Dry Scrubber systems.  The Dry Scrubbers are scheduled to be completed by 2019. More detail regarding the ECP can be found under “Pending Regulatory Matters” in Note 13.

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

39

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.  The Company obtains refunds from the recycling of scrap metal, salvaged transformers and used transformer oil.  Additional savings are 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.

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 2016 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 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).

40

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2016Form 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.

There have been no significant changes in the Company's risk factors from those discussed in the Company's 2016Form 10-K, which are incorporated herein by reference.

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

None.

Item 6.  Exhibits.

Exhibit No.	Description
3.01	OGE Energy Corp. By-laws, as amended on February 22, 2017 (Filed as Exhibit 3.01 to the Company's Form 8-K filed February 22, 2017 (File No. 1-12579) and incorporated by reference herein).
4.01	Supplemental Indenture No. 16 dated as of March 15, 2017 between OG&E and UMB Bank, N.A., as trustee (Filed as Exhibit 4.01 to OG&E's Form 8-K filed March 31, 2017 (File No. 1-1097) and incorporated by reference herein).
10.01	Credit Agreement dated as of March 8, 2017 by and among OGE Energy Corp. and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto (Filed as Exhibit 99.01 to the Company's Form 8-K filed March 8, 2017 (File No. 1-12579) and incorporated by reference herein).
10.02	Credit Agreement dated as of March 8, 2017 by and among Oklahoma Gas and Electric Company and JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Banks, Ltd., MUFG Union Bank, N.A., Royal Bank of Canada and U.S. Bank National Association, as Co-Documentation Agents, and the lenders from time to time parties thereto (Filed as Exhibit 99.01 to the Company's Form 8-K filed March 8, 2017 (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.
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.

41

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)

May 3, 2017

42

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: May 3, 2017

  /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: May 3, 2017

  /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 endedMarch 31, 2017, 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.

May 3, 2017

          /s/ Sean Trauschke

               Sean Trauschke

President and Chief Executive Officer

          /s/ Stephen Merrill

               Stephen Merrill

Chief Financial Officer

XML

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2017	Jan. 31, 2017
Document Information [Line Items]
Entity Registrant Name	OGE ENERGY CORP.
Entity Central Index Key	0001021635
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		199,704,099

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING REVENUES	$ 456.0	$ 433.1
COST OF SALES	208.7	177.9
OPERATING EXPENSES
Other operation and maintenance	124.0	113.9
Depreciation and amortization	55.6	78.5
Taxes other than income	23.9	24.9
Total operating expenses	203.5	217.3
OPERATING INCOME	43.8	37.9
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	35.6	28.3
Allowance for equity funds used during construction	6.9	1.6
Other income	8.8	5.6
Other expense	(4.1)	(1.7)
Net other income (expense)	47.2	33.8
INTEREST EXPENSE
Interest on long-term debt	35.9	35.8
Allowance for borrowed funds used during construction	(3.3)	(0.9)
Interest on short-term debt and other interest charges	2.4	1.4
Interest expense	35.0	36.3
INCOME BEFORE TAXES	56.0	35.4
INCOME TAX EXPENSE	20.0	10.2
NET INCOME	$ 36.0	$ 25.2
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.7	199.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING	200.0	199.7
BASIC EARNINGS PER AVERAGE COMMON SHARE	$ 0.18	$ 0.13
DILUTED EARNINGS PER AVERAGE COMMON SHARE	0.18	0.13
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.30250	$ 0.27500

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Net income	$ 36.0	$ 25.2
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4 and $0.4, respectively	0.6	0.8
Postretirement Benefit Plans:
Amortization of prior service cost, net of tax of ($0.0) and ($0.2), respectively	0.0	(0.4)
Other comprehensive income, net of tax	0.6	0.4
Comprehensive income	$ 36.6	$ 25.6

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) Parenthetical - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss	$ 0.4	$ 0.4
Settlement cost	0.0	0.0
Postretirement Benefit Plans:
Amortization of deferred net loss	0.0	0.0
Amortization of prior service cost	$ 0.0	$ (0.2)

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 36.0	$ 25.2
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	55.6	78.5
Deferred income taxes and investment tax credits, net	20.4	10.4
Equity in earnings of unconsolidated affiliates	(35.6)	(28.3)
Distributions from unconsolidated affiliates	35.3	28.7
Allowance for equity funds used during construction	(6.9)	(1.6)
Stock-based compensation	2.1	1.7
Regulatory assets	(6.4)	(2.3)
Regulatory liabilities	(4.6)	(4.6)
Other assets	(4.0)	2.5
Other liabilities	6.2	2.1
Change in certain current assets and liabilities
Accounts receivable, net	36.4	38.0
Accounts receivable - unconsolidated affiliates	(3.3)	(1.2)
Accrued unbilled revenues	3.5	2.1
Fuel, materials and supplies inventories	(7.7)	10.2
Fuel clause under recoveries	(22.1)	0.0
Other current assets	4.3	(10.0)
Accounts payable	24.9	(44.1)
Fuel clause over recoveries	0.0	2.0
Other current liabilities	(43.1)	(35.9)
Net Cash Provided from Operating Activities	91.0	73.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(219.9)	(177.7)
Return of capital - equity method investments	0.0	6.6
Net Cash Used in Investing Activities	(219.9)	(171.1)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(60.4)	(54.9)
Proceeds from long-term debt	297.1	0.0
Payment of long-term debt	(0.1)	(110.1)
Increase (decrease) in short-term debt	(108.0)	187.5
Net cash provided from financing activities	128.6	22.5
NET CHANGE IN CASH AND CASH EQUIVALENTS	(0.3)	(75.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	0.3	75.2
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 0.0	$ 0.0

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 0.0	$ 0.3
Accounts receivable, less reserve of $1.1 and $1.5, respectively	136.6	173.0
Accounts receivable - unconsolidated affiliates	5.8	2.5
Accrued unbilled revenues	56.2	59.7
Income taxes receivable	13.4	19.4
Fuel inventories	86.3	79.8
Materials and supplies, at average cost	82.9	81.7
Fuel clause under recoveries	73.4	51.3
Other	83.5	81.8
Total current assets	538.1	549.5
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,158.9	1,158.6
Other	75.5	73.6
Total other property and investments	1,234.4	1,232.2
PROPERTY, PLANT AND EQUIPMENT
In service	10,730.8	10,690.0
Construction work in progress	673.3	495.1
Total property, plant and equipment	11,404.1	11,185.1
Less accumulated depreciation	3,503.8	3,488.9
Net property, plant and equipment	7,900.3	7,696.2
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	403.1	404.8
Other	59.0	56.9
Total deferred charges and other assets	462.1	461.7
TOTAL ASSETS	10,134.9	9,939.6
CURRENT LIABILITIES
Short-term debt	128.2	236.2
Accounts payable	244.3	205.4
Dividends payable	60.4	60.4
Customer deposits	78.6	77.7
Accrued taxes	25.2	41.3
Accrued interest	33.0	40.4
Accrued compensation	25.5	45.1
Long-term debt due within one year	224.8	224.7
Other	95.0	96.0
Total current liabilities	915.0	1,027.2
LONG-TERM DEBT	2,703.2	2,405.8
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	276.5	274.8
Deferred income taxes	2,332.0	2,334.5
Regulatory liabilities	306.7	299.7
Other	157.1	153.8
Total deferred credits and other liabilities	3,072.3	3,062.8
Total liabilities	6,690.5	6,495.8
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,107.9	1,105.8
Retained earnings	2,365.2	2,367.3
Accumulated other comprehensive loss, net of tax	(28.7)	(29.3)
Total stockholders' equity	3,444.4	3,443.8
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 10,134.9	$ 9,939.6

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) Parenthetical - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Allowance for Doubtful Accounts Receivable	$ 1.1	$ 1.5

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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, 2015	$ 3,326.0	$ 2.0	$ 1,099.3	$ 2,259.8	$ (35.1)
Changes in Stockholders' Equity
Net income	25.2	0.0	0.0	25.2	0.0
Other comprehensive income, net of tax	0.4	0.0	0.0	0.0	0.4
Dividends declared on common stock	(54.9)	0.0	0.0	(54.9)	0.0
Stock-based compensation	1.6	0.0	1.6	0.0	0.0
Balance at Mar. 31, 2016	3,298.3	2.0	1,100.9	2,230.1	(34.7)
Balance at Dec. 31, 2016	3,443.8	2.0	1,103.8	2,367.3	(29.3)
Changes in Stockholders' Equity
Net income	36.0	0.0	0.0	36.0	0.0
Other comprehensive income, net of tax	0.6	0.0	0.0	0.0	0.6
Dividends declared on common stock	(60.4)	0.0	0.0	(60.4)	0.0
Stock-based compensation	2.1	0.0	2.1	0.0	0.0
Balance at Mar. 31, 2017	3,444.4	2.0	1,105.9	2,365.2	(28.7)
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 22.3	$ 0.0	$ 0.0	$ 22.3	$ 0.0

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

Summary of Significant Accounting Policies

Organization

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

The electric utility 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 the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company atMarch 31, 2017andDecember 31, 2016, the results of its operations for the three months endedMarch 31, 2017and2016 and its cash flows for thethree months endedMarch 31, 2017and2016, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring afterMarch 31, 2017up to the date of issuance of these Condensed Consolidated Financial Statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company'soperating results for thethree months endedMarch 31, 2017are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2017or 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 2016Form 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:

	March 31,		December 31,
(In millions)	2017		2016
Regulatory Assets
Current
Fuel clause under recoveries	$	73.4	$	51.3
Oklahoma demand program rider under recovery (A)	45.6		51.0
SPP cost tracker under recovery (A)	14.6		10.0
Other (A)	8.6		9.5
Total Current Regulatory Assets	$	142.2	$	121.8
Non-Current
Benefit obligations regulatory asset	$	228.9	$	232.6
Income taxes recoverable from customers, net	65.6		62.3
Deferred storm expenses	40.5		35.7
Smart Grid	38.2		43.2
Unamortized loss on reacquired debt	13.1		13.4
Other	16.8		17.6
Total Non-Current Regulatory Assets	$	403.1	$	404.8
Regulatory Liabilities
Current
Other (B)	$	13.4	$	12.3
Total Current Regulatory Liabilities	$	13.4	$	12.3
Non-Current
Accrued removal obligations, net	$	268.6	$	262.8
Pension tracker	36.6		35.5
Other	1.5		1.4
Total Non-Current Regulatory Liabilities	$	306.7	$	299.7

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

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

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

Asset Retirement Obligation Disclosure [Text Block]

Asset Retirement Obligations

The following table summarizes changes to the Company's asset retirement obligations during thethree months endedMarch 31, 2017and2016.

	Three Months Ended March 31,
(In millions)	2017		2016
Balance at January 1	$	69.6	$	63.3
Accretion expense	0.7		0.7
Balance at March 31	$	70.3	$	64.0

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 three months endedMarch 31, 2017 and 2016. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net income  (loss)			Prior service cost		Net income (loss)		Prior service cost		Total
Balance at December 31, 2016	$	(32.1	)	$	0.1	$	2.7	$	—	$	(29.3	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.6			—		—		—		0.6
Balance at March 31, 2017	$	(31.5	)	$	0.1	$	2.7	$	—	$	(28.7	)

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

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three months endedMarch 31, 2017 and 2016.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended
	March 31,
(In millions)	2017			2016
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.0	)	$	(1.2	)	(A)
	(0.4		)	(0.4		)	Income taxes
	$	(0.6	)	$	(0.8	)	Net of tax
Amortization of postretirement benefit plan items
Prior service credit	$	—		$	0.6		(A)
	—			0.6			Total before tax
	—			0.2			Income taxes
	$	—		$	0.4		Net of tax
Total reclassifications for the period	$	(0.6	)	$	(0.4	)	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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Accounting Pronouncements

3 Months Ended

Mar. 31, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

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

Accounting Pronouncements

Revenue from Contracts with Customers.In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". The new guidance was intended to be effective for fiscal years beginning after December 15, 2016. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year. Reporting entities may choose to adopt the standard as of the original effective date. The deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. The Company currently expects to apply the modified retrospective transition method, but will ultimately determine its transition approach once various industry issues have been resolved. Currently, the Company is not aware of any issues that would have a material impact on the timing of revenue recognition. The Company is assessing the effect of this new guidance on its tariff-based sales, bundled arrangements and alternative revenue programs. At this time, the Company is evaluating the impact of the new standard on its results of operations and financial position, but believes that it will change the income statement presentation of revenues and will require new disclosures.

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 started evaluating its current lease contracts. The Company has not determined the amount of impact on its Condensed Consolidated Financial Statements, but it anticipates an increase in the recognition of right-of-use assets and lease liabilities.

Employee Share Based Payment Accounting.In March 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share Based Payment Accounting," which amends Accounting Standards Codification Topic 718, Compensation - Stock Compensation. ASU 2016-09 includes provisions intended to simplify various aspects related to how share based payments are accounted for and presented in the financial statements.The new guidance among other requirements requires all of the tax effects related to share based payments at settlement (or expiration) to be recorded through the income statement. Previously, tax benefits in excess of compensation cost, or windfalls, were recorded in equity, and tax deficiencies, or shortfalls, were recorded in equity to the extent of previous windfalls, and then to the income statement. Under the new guidance, the windfall tax benefit is recorded when it arises, subject to normal valuation allowance considerations. This change is required to be applied on a modified retrospective basis, with a cumulative effect adjustment to opening retained earnings. All tax related cash flows resulting from share based payments are to be reported as operating activities on the statement of cash flows, a change from the previous requirement to present windfall tax benefits as an inflow from financing activities and an outflow from operating activities. The Company adopted this standard in the first quarter of 2017, and recorded a cumulative effect of $22.3 million as a deferred tax asset with an offset in retained earnings. Going forward, tax benefits in excess of compensation costs previously recorded in equity will be recorded within the income statement and all tax related cash flows resulting from share based payments will be recorded as an operating activity within the statement of cash flows.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. In May 2017, the FASB issued ASU 2017-07, “Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.”  The new guidance is designed to improve the reporting of pension and other postretirement benefit costs by bifurcating the components of net benefit expense between those that are attributed to compensation for service and those that are not.  The service cost component of benefit expense will continue to be presented within operating income, but entities will now be required to present the other components of benefit expense as non-operating within the income statement.  Additionally, the new guidance only permits the capitalization of the service cost component of net benefit expense.

The accounting change is required to be applied using a modified retrospective approach for the presentation of components of net benefit cost, and on a prospective basis for the capitalization of only the service cost component of net benefit costs.  The new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Early adoption is permitted, subject to certain conditions.

The Company believes that the impact of the change in capitalization of only the service cost component of net periodic benefit costs will be immaterial from current practice.  The Company does not intend to early adopt the new guidance and will implement the change in the first quarter of 2018.

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Investment in Unconsolidated Affiliates

3 Months Ended

Mar. 31, 2017

Related Party Transactions [Abstract]

Equity Method Investments and Joint Ventures Disclosure [Text Block]

Investment in Unconsolidated Affiliate

The Company's investment in Enable is considered to be a variable interest entity because the owners of the equity at risk in this entity have disproportionate voting rights in relation to their obligations to absorb the entity's expected losses or to receive its expected residual returns. However, the Company is not considered the primary beneficiary of Enable since it does not have the power to direct the activities of Enable that are considered most significant to the economic performance of Enable, therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at March 31, 2017. 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.

Enable completed an initial public offering resulting in Enable becoming a publicly traded Master Limited Partnership in April 2014. At March 31, 2017, the Company owned 111.0 million common units, or 25.7 percent of Enable's outstanding common units. Of the Company's 111.0 million common units, 68.2 million units were subordinated. The subordination period began on the closing date of Enable's initial public offering and will extend until the first business day following the distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equal to or exceeding $1.15 per unit (the annualized minimum quarterly distribution) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding June 30, 2017. The Company anticipates that the subordination period will expire in August 2017 and will not impact future distributions that the Company receives from Enable.

On May 2, 2017, Enable announced a quarterly dividend distribution of $0.31800 per unit on its outstanding common and subordinated units, which is unchanged from the previous quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages, up to 50 percent, of the cash Enable distributes in excess of that amount. The Company is entitled to 60 percent of those "incentive distributions." In certain circumstances, the general partner has the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

Distributions received from Enable were $35.3 million during the three months endedMarch 31, 2017 and 2016.

On January 16, 2017, CenterPoint and its wholly owned subsidiary, CenterPoint Energy Resources Corp., provided a second notice to the Company of CenterPoint's solicitation of offers from unrelated third parties to acquire all or any portion of the common units and subordinated units of Enable owned by CenterPoint Energy Resources Corp. and all of the membership interests of the general partner of Enable owned by CenterPoint Energy Resources Corp. On February 15, 2017, under the terms of right of first offer, the Company submitted to CenterPoint another proposal to acquire, in conjunction with a third party, all of CenterPoint's membership interests in Enable GP and all of the common units and subordinated units of Enable owned by CenterPoint. The Company did not receive a reply from CenterPoint within the required timeframe. In accordance with the provisions of the partnership agreement, CenterPoint has until July 15, 2017 to solicit additional offers in excess of the Company's offer.

If the Company's proposal had been accepted by CenterPoint, and if the transaction contemplated by the proposal was in fact consummated, the Company anticipated that the third party would, as a result of such transaction, become the owner of all or substantially all of the securities subject to the right of first offer. The Company's ownership interest in Enable would not have materially changed as a result of such transaction, and therefore the Company would not have been required to consolidate the financial results of Enable with the financial results of the Company.

The Company cannot predict what future actions CenterPoint will take, if any, associated with their ownership interest in Enable.

Related Party Transactions

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

In connection with the formation of Enable, the Company and Enable entered into a Services Agreement, an Employee Transition Agreement, and other agreements whereby the Company agreed to provide certain support services to Enable such as accounting, legal, risk management and treasury functions for an initial term ending on April 30, 2016. As of December 31, 2015, Enable terminated all support services except certain information technology, payroll and benefits administration. The remaining services automatically extended for another year on May 1, 2017. Under these agreements, the Company charged operating costs to Enable of $0.8 million and $1.3 million for the three months endedMarch 31, 2017 and 2016, respectively. The Company charges operating costs to OG&E and Enable based on several factors. Operating costs directly related to OG&E and/or Enable are assigned as such.  Operating costs incurred for the benefit of OG&E are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

The Company agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October 2014, the Company, CenterPoint and Enable agreed to continue the secondment to Enable of 192 employees that participate in the Company's defined benefit and retirement plans beyond December 31, 2014. The Company billed Enable for reimbursement of $10.0 million and $8.3 million during the three months endedMarch 31, 2017 and 2016, respectively, under the Transitional Seconding Agreement for employment costs. If the seconding agreement was terminated, and those employees were no longer employed by the Company, and lump sum payments were made to those employees, the Company would recognize a settlement or curtailment of the pension/retiree health care charges, which would increase expense at the Company by approximately $20.9 million. Settlement and curtailment charges associated with the Enable seconded employees are not reimbursable to the Company by Enable. The seconding agreement can be terminated by mutual agreement of the Company and Enable or solely by the Company upon 120 day notice.

The Company had accounts receivable from Enable for amounts billed for transitional services, including the cost of seconded employees, of $5.9 million as of March 31, 2017 and $2.7 million as of December 31, 2016, respectively.

Enable provides gas transportation services to OG&E pursuant to an agreement that expires in April 2019. This transportation agreement grants Enable the responsibility of delivering natural gas to OG&E’s generating facilities and performing an imbalance service. With this imbalance service, in accordance with the cash-out provision of the contract, OG&E purchases gas from Enable when Enable’s deliveries exceed OG&E’s pipeline receipts. Enable purchases gas from OG&E when OG&E’s pipeline receipts exceed Enable’s deliveries.The following table summarizes related party transactions between OG&E and Enable during thethree months endedMarch 31, 2017 and 2016.

	Three Months Ended
	March 31,
(In millions)	2017			2016
Operating Revenues:
Electricity to power electric compression assets	$	2.2		$	2.3
Cost of Sales:
Natural gas transportation services	$	8.8		$	8.8
Natural gas purchases/(sales)	(0.4		)	1.5

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at March 31, 2017 and December 31, 2016 and for the three months endedMarch 31, 2017 and 2016.

	March 31,		December 31,
Balance Sheet	2017		2016
(In millions)
Current assets	$	375	$	396
Non-current assets	10,786		10,816
Current liabilities	279		362
Non-current liabilities	3,111		3,056

	Three Months Ended
	March 31,
Income Statement	2017		2016
(In millions)
Operating revenues	$	666	$	509
Cost of natural gas and natural gas liquids	308		195
Operating income	140		103
Net income	111		86

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 $35.6 million and $28.3 million for the three months endedMarch 31, 2017 and 2016, respectively. Equity in earnings of unconsolidated affiliates includes the Company's share of Enable's earnings adjusted for the amortization of the basis difference of the Company's original investment in Enogex and its underlying equity in the net assets of Enable. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed, beginning in May 2013. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described below.

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for thethree months endedMarch 31, 2017 and 2016.

	Three Months Ended
	March 31,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2017			2016
(In millions)
Enable net income	$	110.8		$	86.0
Differences due to timing of OGE Energy and Enable accounting close	—			(11.7		)
Enable net income used to calculate OGE Energy's equity in earnings	$	110.8		$	74.3
OGE Energy’s percent ownership at period end	25.7		%	26.3		%
OGE Energy’s portion of Enable net income	$	28.5		$	19.5
Impairments recognized by Enable associated with OGE Energy’s basis differences	—			1.8
OGE Energy's share of Enable net income	$	28.5		$	21.3
Amortization of basis difference	2.8			2.9
Elimination of Enable fair value step up	4.3			4.1
Equity in earnings of unconsolidated affiliates	$	35.6		$	28.3

The difference between the OGE Energy's investment in Enable and its underlying equity in the net assets of Enable was $736.6 million as of March 31, 2017. The following table reconciles the basis difference in Enable from December 31, 2016 to March 31, 2017.

(In millions)
Basis difference as of December 31, 2016	$	743.7
Amortization of basis difference	(2.8		)
Elimination of Enable fair value step up	(4.3		)
Basis difference as of March 31, 2017	$	736.6

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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

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

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

The Company had nofinancial instruments measured at fair value on a recurring basis atMarch 31, 2017 and December 31, 2016.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at March 31, 2017 and December 31, 2016.

	March 31,				December 31,
	2017				2016
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt (including Long-Term Debt due within one year)
Senior Notes	$	2,683.0	$	2,941.5	$	2,385.5	$	2,657.2
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.8		9.3		9.9		9.5
OGE Energy Senior Notes	99.8		100.0		99.7		99.9

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Stock-Based Compensation

3 Months Ended

Mar. 31, 2017

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

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

Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree months endedMarch 31, 2017 and 2016related to the Company's performance units and restricted stock.

	Three Months Ended March 31,
(In millions)	2017		2016
Performance units
Total shareholder return	$	1.5	$	1.1
Earnings per share	0.6		0.6
Total performance units	2.1		1.7
Restricted stock	—		—
Total compensation expense	2.1		1.7
Income tax benefit	$	0.8	$	0.6

During thethree months endedMarch 31, 2017, the Company issued an immaterial number of shares to satisfy restricted stock grants.

The following table summarizes the activity of the Company's stock-based compensation during thethree months endedMarch 31, 2017.

	Units/Shares	Fair Value Per Share
Grants
Performance units (Total shareholder return)	260,570	$	41.77
Performance units (Earnings per share)	86,857	$	34.95

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Income Taxes

3 Months Ended

Mar. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions.With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to2013or state and local tax examinations by tax authorities for years prior to2012.  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

3 Months Ended

Mar. 31, 2017

Common Equity [Text Block]

Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued no shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three months endedMarch 31, 2017.  

Earnings Per Share

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

	Three Months Ended March 31,
(In millions except per share data)	2017		2016
Net income	$	36.0	$	25.2
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.3		—
Diluted average common shares outstanding	200.0		199.7
Basic Earnings Per Average Common Share	$	0.18	$	0.13
Diluted Earnings Per Average Common Share	$	0.18	$	0.13
Anti-dilutive shares excluded from earnings per share calculation	—		—

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Long-Term Debt

3 Months Ended

Mar. 31, 2017

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

Long-Term Debt

AtMarch 31, 2017, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

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

SERIES			DATE DUE	AMOUNT
				(In millions)
0.65%	-	0.95%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.65%	-	0.90%	Muskogee Industrial Authority, January 1, 2025	32.4
0.66%	-	0.95%	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.

Issuance of New Long-Term Debt

In March 2017, OG&E issued $300.0 millionof 4.15 percentsenior notes dueApril 1, 2047. The proceeds from the issuance were used to repay short-term debt and were added to OG&E's general funds to be used for general corporate purposes, including to repay borrowings under the revolving credit facility, to fund the payment at maturity of OG&E's$125.0 millionof 6.5 percentsenior notes due July 15, 2017, and to fund ongoing capital expenditures and working capital.

Expected Issuance of Long-Term Debt

OG&E expects to issue up to$300.0 millionof long-term debt during the second half of 2017, depending on market conditions, to fund capital expenditures, to repay short or long-term borrowings and for general corporate purposes.

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Short-Term Debt and Credit Facilities

3 Months Ended

Mar. 31, 2017

Short-term Debt [Abstract]

Short-Term Debt and Credit Facilities

Short-Term Debt and CreditFacilities

On March 8, 2017 the Company and OG&E each entered into new $450.0 million unsecured five-year revolving credit facilities to replace existing facilities. Each of these new facilities is scheduled to terminate on March 8, 2022. However, the Company and OG&E have the right to request an extension of the revolving credit facility termination date under their respective facility for an additional one-year period, which can be exercised up to two times. All such extension requests are subject to majority lender group approval (and only the commitments of those lenders that consent to such extension (or that agree to replace any non-consenting lender) will be extended for such additional period).

Borrowings under the new facilities bear interest at rates equal to either the eurodollar base rate (reserve adjusted, if applicable), plus a margin of 0.69 percent to 1.275 percent, or an alternate base rate, plus a margin of 0.0 percent to 0.275 percent. The new facilities have a facility fee that ranges from 0.06 percent to 0.225 percent. Interest rate margins and facility fees are based on the Company's and OG&E's then-current senior unsecured credit ratings, as applicable.

Each of the facilities provides for issuance of letters of credit, provided that (i) the aggregate outstanding credit exposure shall not exceed the amount of the revolving credit facility and (ii) the aggregate outstanding stated amount of letters of credit issued under such facility shall not exceed a specified maximum sublimit ($100 million for each of the Company and OG&E). Advances under the facilities may be used to refinance existing indebtedness and for working capital and general corporate purposes of the respective borrower and its subsidiaries, including commercial paper liquidity support, letters of credit, acquisitions and distributions.

Each of the facilities is unsecured and, under certain circumstances, may be increased (by up to $150 million in each case for the Company and OG&E), to a maximum revolving commitment limit of $600 million. Advances of revolving loans and letters of credit under the facilities are subject to certain conditions precedent, including the accuracy of certain representations and warranties and the absence of any default or unmatured default.

The Company and OG&E's facilities each has a financial covenant requiring that the respective borrower maintain a maximum debt to capitalization ratio of 65 percent, as defined in each such facility. The Company and OG&E's facilities each also contains covenants which restrict the respective borrower and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of liens and transactions with affiliates. The Company and OG&E's facilities are each subject to acceleration upon the occurrence of any default, including, among others, payment defaults on such facilities, breach of representations, warranties and covenants, acceleration of indebtedness (other than intercompany and non-recourse indebtedness) of $100.0 million or more in the aggregate, change of control (as defined in each such facility), nonpayment of uninsured judgments in excess of $100.0 million, and the occurrence of certain Employee Retirement Income Security Act and bankruptcy events, subject where applicable to specified cure periods.

As ofMarch 31, 2017, the Company had$128.2 millionof short-term debt as compared to$236.2 million at December 31, 2016. The following table provides information regarding the Company's revolving credit agreements at March 31, 2017.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	128.2	1.219	%	(D)	March 8, 2022
OG&E (C)	450.0		1.8		0.95	%	(D)	March 8, 2022
Total	$	900.0	$	130.0	1.214	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2017.

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

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

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

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions.Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse rating impact occurs. The impact of any future downgrade could include an increase in the costs of the Company's short-term borrowings, but a reduction in the Company's credit ratings would not result in any defaults or accelerations.Any future 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, 2017 and ending December 31, 2018.

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Retirement Plans and Postretirement Benefit Plans

3 Months Ended

Mar. 31, 2017

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

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

Net Periodic Benefit Cost

	Pension Plan						Restoration of Retirement Income Plan				Postretirement Benefit Plans
	Three Months Ended						Three Months Ended				Three Months Ended
	March 31,						March 31,				March 31,
(In millions)	2017 (B)			2016 (B)			2017 (B)		2016 (B)		2017 (B)			2016 (B)
Service cost	$	4.2		$	4.4		$	0.1	$	0.1	$	0.2		$	0.3
Interest cost	6.5			6.6			0.1		0.1		2.2			2.3
Expected return on plan assets	(10.7		)	(10.5		)	—		—		(0.6		)	(0.6		)
Amortization of net loss	4.0			4.2			0.1		0.2		0.6			0.5
Amortization of unrecognized prior service cost (A)	—			—			—		—		—			(2.2		)
Total net periodic benefit cost	4.0			4.7			0.3		0.4		2.4			0.3
Less: Amount paid by unconsolidated affiliates	0.8			1.3			—		—		0.4			0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.2		$	3.4		$	0.3	$	0.4	$	2.0		$	0.2

(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$5.5 millionand$4.0 millionof net periodic benefit cost recognizedduring thethree months endedMarch 31, 2017and2016, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedMarch 31, 2017 and 2016of$2.9 millionand$2.3 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1); and

• an increase in postretirement medical expense in the three months endedMarch 31, 2017 and 2016 of $1.1 million and $2.0 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 for regulatory liability (see Note 1).

	Three Months Ended
	March 31,
(In millions)	2017		2016
Capitalized portion of net periodic pension benefit cost	$	1.0	$	1.2
Capitalized portion of net periodic postretirement benefit cost	0.7		0.1

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Report of Business Segments

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

Report of Business Segments

Report of Business Segments

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

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

The following tables summarize the results of the Company's business segments during the three months endedMarch 31, 2017 and 2016.

Three Months Ended March 31, 2017	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	456.0	$	—		$	—		$	—		$	456.0
Cost of sales	208.7		—			—			—			208.7
Other operation and maintenance	126.1		0.1			(2.2		)	—			124.0
Depreciation and amortization	54.7		—			0.9			—			55.6
Taxes other than income	22.3		0.2			1.4			—			23.9
Operating income (loss)	44.2		(0.3		)	(0.1		)	—			43.8
Equity in earnings of unconsolidated affiliates	—		35.6			—			—			35.6
Other income (expense)	12.9		0.1			(1.3		)	(0.1		)	11.6
Interest expense	33.6		—			1.5			(0.1		)	35.0
Income tax expense (benefit)	7.3		15.4			(2.7		)	—			20.0
Net income (loss)	$	16.2	$	20.0		$	(0.2	)	$	—		$	36.0
Investment in unconsolidated affiliates	$	—	$	1,158.9		$	—		$	—		$	1,158.9
Total assets	$	8,950.9	$	1,521.2		$	91.1		$	(428.3	)	$	10,134.9

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

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2017

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 Notes13and14 to the Company's Consolidated Financial Statements included in the Company's 2016Form 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. Management believes that all of its operations are in substantial compliance with current Federal, state and local environmental standards.

Environmental regulation can increase the cost of planning, design, initial installation and operation of OG&E's facilities. Historically, OG&E's total expenditures for environmental control facilities and for remediation have not been significant in relation to 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.

Air Quality Control System

On September 10, 2014, OG&E executed a contract for the design, engineering and fabrication of two circulating Dry Scrubber systems to be installed at Sooner Units 1 and 2.  OG&E entered into an agreement on February 9, 2015, to install the Dry Scrubber systems.  The Dry Scrubbers are scheduled to be completed by 2019. More detail regarding the ECP can be found under “Pending Regulatory Matters” in Note 13.

Other

In the normal course of business,the 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

3 Months Ended

Mar. 31, 2017

Regulated Operations [Abstract]

Rate Matters and Regulation

Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note14to the Company's Consolidated Financial Statements included in the Company's 2016Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Oklahoma Rate Case Filing

On December 18, 2015, OG&E filed a general rate case with the OCC requesting a rate increase of $92.5 millionand a10.25 percent return on equity based on a common equity percentage of 53 percent. The rate case was based on a June 30, 2015 test year and included recovery of $1.6 billionof electric infrastructure additions since its last general rate case in Oklahoma.

On July 1, 2016, OG&E implemented an annual interim rate increase of $69.5 million, subject to refund for amounts in excess of the rates approved by the OCC. As of March 31, 2017 OG&E has fully reserved all of the interim rate increase pending resolution of the refund methodology.

In December 2016, the ALJ issued a report and recommendations in the case. The ALJ's recommendations included, among other things, the use of OG&E's actual capital structure of53.0 percent equity and47.0 percentlong-term debt and a return on equity of 9.87 percentresulting in an annual increase in OG&E's revenues of $40.7 million.

On March 20, 2017, the OCC held hearings and issued a final order. The final order results in an annual net increase of approximately$8.8 millionin OG&E's rates to its Oklahoma retail customers. Although the final order adopted certain of the recommendations set forth in the ALJ Report, it differs in certain key respects.

The primary adjustments to the ALJ report consist of: (i) Oklahoma retail authorized rate of return on equity of 9.50 percent, (ii) depreciation expense is reduced by approximately$28.6 millionfrom the ALJ report or $36.4 millionfrom current rates on an annual basis, (iii) recovery of only 50.0 percent of short-term incentive compensation and no recovery of long-term incentive compensation, (iv) recovery of OG&E's requested vegetation management expenses and (v) recovery of production tax credits expiring in 2017 and air quality control systems consumable costs through the fuel adjustment clause.

As a result of the final order, OG&E recorded in the first quarter of 2017, adjustments to depreciation expense, amortization of regulatory assets and liabilities, and impacts to the fuel adjustment clause effective July 1, 2016. On May 1, 2017, OG&E implemented new rates and began refunding excess amounts that it had collected in interim rates.

Pending Regulatory Matters

Set forth below is a list of various proceedings pending before state or federal regulatory agencies. Unless stated otherwise, OG&E cannot predict when the regulatory agency will act or what action the regulatory agency will take. OG&E's financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze Rule FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application sought approval of the ECP and for a recovery mechanism for the associated costs. The ECP includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asked the OCC to predetermine the prudence of its Mustang Modernization Plan, which calls for replacing OG&E's soon-to-be retired Mustang steam turbines with 400 MWs of new, efficient combustion turbines at the Mustang site and approval for a recovery mechanism for the associated costs.

On December 2, 2015, OG&E received an order from the OCC denying its plan to comply with the environmental mandates of the Federal Clean Air Act, Regional Haze Rule and MATS. The OCC also denied OG&E's request for pre-approval of its Mustang Modernization Plan, revised depreciation rates for both the retirement of the Mustang units and the replacement combustion turbines and pre-approval of early retirement and replacement of generating units at its Mustang site, including cost recovery through a rider.

On February 12, 2016, OG&E filed an application requesting the OCC to issue an order approving its decision to install Dry Scrubbers at the Sooner facility. OG&E's application did not seek approval of the costs of the Dry Scrubber project. Instead, the reasonableness of the costs would be considered after the project is completed and OG&E seeks recovery in its rates.On April 28, 2016, the OCC approved the Dry Scrubber project.

Two parties appealed the OCC's decision to the Oklahoma Supreme Court. The Company is unable to predict what action the Oklahoma Supreme Court may take or the timing of any such action.

OG&E anticipates the total cost of Dry Scrubbers will be $547.5 million, including allowance for funds used during construction and capitalized ad valorem taxes. As of March 31, 2017, OG&E had invested$281.6 millionof construction work in progress on the Dry Scrubbers.OG&E anticipates the total cost for the Mustang Modernization Plan will be$424.9 millionand expects the project to be completed in late 2017. As ofMarch 31, 2017, OG&E had invested $231.8 millionon the Mustang Modernization Plan.

Integrated Resource Plans

In October 2015, OG&E finalized the 2015 IRP and submitted it to the OCC. The 2015 IRP updated certain assumptions contained in the IRP submitted in 2014, but did not make any material changes to the ECP and other parts of the plan. Currently, OG&E is scheduled to update its IRP in Arkansas by October 1, 2017 and in Oklahoma by October 1, 2018.

Arkansas Rate Case Filing

On August 25, 2016, OG&E filed a general rate case with the APSC. The rate filing requested a $16.5 millionrate increase based on a 10.25 percentreturn on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over$3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management, and increased recovery of depreciation and dismantlement costs.

In April 2017, OG&E entered into a settlement with the staff of the APSC and other intervenors. The settlement provides for a $7.1 millionannual rate increase and a9.5 percentreturn on equity on a50.0 percentequity capital structure. The settlement is subject to approval of the APSC. Hearings are scheduled for the APSC to review the settlement on May 2, 2017. OG&E expects to receive an order from the APSC in the second quarter of 2017.

The settlement also provides that OG&E will be regulated under a formula rate rider, which should result in a more efficient process as the return on equity, depreciation rates and capital structure should not change from what is approved by the APSC in the current rate case proceeding unless differences of plus or minus 50 basis points in return on equity were to occur. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC. OG&E expects to make its first filing under the Arkansas Formula Rate Rider in October 2018.

Fuel Adjustment Clause Review for Calendar Year 2015

On September 8, 2016, the OCC staff filed an application to review OG&E’s fuel adjustment clause for calendar year 2015, including the prudence of OG&E’s electric generation, purchased power and fuel procurement costs. At a hearing on March 30, 2017, the PUD staff recommended to the OCC that the 2015 fuel costs be found prudent. The Company expects to receive an OCC order in the second quarter of 2017.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Consolidation, Policy [Policy Text Block]

Organization

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

The electric utility 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 the Company and CenterPoint, who each have 50 percent management ownership. Based on the 50/50 management ownership, with neither company having control, the Company began accounting for its interest in Enable using the equity method of accounting.

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company atMarch 31, 2017andDecember 31, 2016, the results of its operations for the three months endedMarch 31, 2017and2016 and its cash flows for thethree months endedMarch 31, 2017and2016, have been included and are of a normal recurring nature except as otherwise disclosed. Management also has evaluated the impact of events occurring afterMarch 31, 2017up to the date of issuance of these Condensed Consolidated Financial Statements and these statements contain all necessary adjustments and disclosures resulting from that evaluation.

Due to seasonal fluctuations and other factors, the Company'soperating results for thethree months endedMarch 31, 2017are not necessarily indicative of the results that may be expected for the year endingDecember 31, 2017or 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 2016Form 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, therefore, the Company accounts for its investment in Enable using the equity method of accounting. Under the equity method, the investment will be adjusted each period for contributions made, distributions received and the Company's share of the investee's comprehensive income as adjusted for basis differences. The Company's maximum exposure to loss related to Enable is limited to the Company's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at March 31, 2017. 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).

	March 31,				December 31,
	2017				2016
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt (including Long-Term Debt due within one year)
Senior Notes	$	2,683.0	$	2,941.5	$	2,385.5	$	2,657.2
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.8		9.3		9.9		9.5
OGE Energy Senior Notes	99.8		100.0		99.7		99.9

Income Tax, Policy [Policy Text Block]

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

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

Earnings Per Share, Policy [Policy Text Block]

Earnings Per Share

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

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

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

	March 31,		December 31,
(In millions)	2017		2016
Regulatory Assets
Current
Fuel clause under recoveries	$	73.4	$	51.3
Oklahoma demand program rider under recovery (A)	45.6		51.0
SPP cost tracker under recovery (A)	14.6		10.0
Other (A)	8.6		9.5
Total Current Regulatory Assets	$	142.2	$	121.8
Non-Current
Benefit obligations regulatory asset	$	228.9	$	232.6
Income taxes recoverable from customers, net	65.6		62.3
Deferred storm expenses	40.5		35.7
Smart Grid	38.2		43.2
Unamortized loss on reacquired debt	13.1		13.4
Other	16.8		17.6
Total Non-Current Regulatory Assets	$	403.1	$	404.8
Regulatory Liabilities
Current
Other (B)	$	13.4	$	12.3
Total Current Regulatory Liabilities	$	13.4	$	12.3
Non-Current
Accrued removal obligations, net	$	268.6	$	262.8
Pension tracker	36.6		35.5
Other	1.5		1.4
Total Non-Current Regulatory Liabilities	$	306.7	$	299.7

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

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

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

The following table summarizes changes to the Company's asset retirement obligations during thethree months endedMarch 31, 2017and2016.

	Three Months Ended March 31,
(In millions)	2017		2016
Balance at January 1	$	69.6	$	63.3
Accretion expense	0.7		0.7
Balance at March 31	$	70.3	$	64.0

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 three months endedMarch 31, 2017 and 2016. All amounts below are presented net of tax.

	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net income  (loss)			Prior service cost		Net income (loss)		Prior service cost		Total
Balance at December 31, 2016	$	(32.1	)	$	0.1	$	2.7	$	—	$	(29.3	)
Amounts reclassified from accumulated other comprehensive income (loss)	0.6			—		—		—		0.6
Balance at March 31, 2017	$	(31.5	)	$	0.1	$	2.7	$	—	$	(28.7	)

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

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 months endedMarch 31, 2017 and 2016.

Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended
	March 31,
(In millions)	2017			2016
Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.0	)	$	(1.2	)	(A)
	(0.4		)	(0.4		)	Income taxes
	$	(0.6	)	$	(0.8	)	Net of tax
Amortization of postretirement benefit plan items
Prior service credit	$	—		$	0.6		(A)
	—			0.6			Total before tax
	—			0.2			Income taxes
	$	—		$	0.4		Net of tax
Total reclassifications for the period	$	(0.6	)	$	(0.4	)	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)

3 Months Ended

Mar. 31, 2017

Reconciliation of Basis Difference [Line Items]

Reconciliation of Basis Difference [Table Text Block]

The following table reconciles the basis difference in Enable from December 31, 2016 to March 31, 2017.

(In millions)
Basis difference as of December 31, 2016	$	743.7
Amortization of basis difference	(2.8		)
Elimination of Enable fair value step up	(4.3		)
Basis difference as of March 31, 2017	$	736.6

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 months endedMarch 31, 2017 and 2016.

	Three Months Ended
	March 31,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2017			2016
(In millions)
Enable net income	$	110.8		$	86.0
Differences due to timing of OGE Energy and Enable accounting close	—			(11.7		)
Enable net income used to calculate OGE Energy's equity in earnings	$	110.8		$	74.3
OGE Energy’s percent ownership at period end	25.7		%	26.3		%
OGE Energy’s portion of Enable net income	$	28.5		$	19.5
Impairments recognized by Enable associated with OGE Energy’s basis differences	—			1.8
OGE Energy's share of Enable net income	$	28.5		$	21.3
Amortization of basis difference	2.8			2.9
Elimination of Enable fair value step up	4.3			4.1
Equity in earnings of unconsolidated affiliates	$	35.6		$	28.3

Schedule of Related Party Transactions [Table Text Block]

The following table summarizes related party transactions between OG&E and Enable during thethree months endedMarch 31, 2017 and 2016.

	Three Months Ended
	March 31,
(In millions)	2017			2016
Operating Revenues:
Electricity to power electric compression assets	$	2.2		$	2.3
Cost of Sales:
Natural gas transportation services	$	8.8		$	8.8
Natural gas purchases/(sales)	(0.4		)	1.5

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

Summarized unaudited financial information for 100 percent of Enable is presented below at March 31, 2017 and December 31, 2016 and for the three months endedMarch 31, 2017 and 2016.

	March 31,		December 31,
Balance Sheet	2017		2016
(In millions)
Current assets	$	375	$	396
Non-current assets	10,786		10,816
Current liabilities	279		362
Non-current liabilities	3,111		3,056

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

	Three Months Ended
	March 31,
Income Statement	2017		2016
(In millions)
Operating revenues	$	666	$	509
Cost of natural gas and natural gas liquids	308		195
Operating income	140		103
Net income	111		86

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

Fair Value Disclosures [Abstract]

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

The following table summarizes the fair value and carrying amount of the Company's financial instruments at March 31, 2017 and December 31, 2016.

	March 31,				December 31,
	2017				2016
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt (including Long-Term Debt due within one year)
Senior Notes	$	2,683.0	$	2,941.5	$	2,385.5	$	2,657.2
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Tinker Debt	9.8		9.3		9.9		9.5
OGE Energy Senior Notes	99.8		100.0		99.7		99.9

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Stock-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2017

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

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

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during thethree months endedMarch 31, 2017 and 2016related to the Company's performance units and restricted stock.

	Three Months Ended March 31,
(In millions)	2017		2016
Performance units
Total shareholder return	$	1.5	$	1.1
Earnings per share	0.6		0.6
Total performance units	2.1		1.7
Restricted stock	—		—
Total compensation expense	2.1		1.7
Income tax benefit	$	0.8	$	0.6

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

The following table summarizes the activity of the Company's stock-based compensation during thethree months endedMarch 31, 2017.

	Units/Shares	Fair Value Per Share
Grants
Performance units (Total shareholder return)	260,570	$	41.77
Performance units (Earnings per share)	86,857	$	34.95

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Common Equity (Tables)

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

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

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

	Three Months Ended March 31,
(In millions except per share data)	2017		2016
Net income	$	36.0	$	25.2
Average Common Shares Outstanding
Basic average common shares outstanding	199.7		199.7
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	0.3		—
Diluted average common shares outstanding	200.0		199.7
Basic Earnings Per Average Common Share	$	0.18	$	0.13
Diluted Earnings Per Average Common Share	$	0.18	$	0.13
Anti-dilutive shares excluded from earnings per share calculation	—		—

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2017

Long-term Debt, Unclassified [Abstract]

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

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

SERIES			DATE DUE	AMOUNT
				(In millions)
0.65%	-	0.95%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.65%	-	0.90%	Muskogee Industrial Authority, January 1, 2025	32.4
0.66%	-	0.95%	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)

3 Months Ended

Mar. 31, 2017

Short-term Debt [Abstract]

Schedule of Line of Credit Facilities [Table Text Block]

The following table provides information regarding the Company's revolving credit agreements at March 31, 2017.

	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Expiration
(In millions)
OGE Energy (B)	$	450.0	$	128.2	1.219	%	(D)	March 8, 2022
OG&E (C)	450.0		1.8		0.95	%	(D)	March 8, 2022
Total	$	900.0	$	130.0	1.214	%

(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2017.

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

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

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

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Retirement Plans and Postretirement Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2017

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				Postretirement Benefit Plans
	Three Months Ended						Three Months Ended				Three Months Ended
	March 31,						March 31,				March 31,
(In millions)	2017 (B)			2016 (B)			2017 (B)		2016 (B)		2017 (B)			2016 (B)
Service cost	$	4.2		$	4.4		$	0.1	$	0.1	$	0.2		$	0.3
Interest cost	6.5			6.6			0.1		0.1		2.2			2.3
Expected return on plan assets	(10.7		)	(10.5		)	—		—		(0.6		)	(0.6		)
Amortization of net loss	4.0			4.2			0.1		0.2		0.6			0.5
Amortization of unrecognized prior service cost (A)	—			—			—		—		—			(2.2		)
Total net periodic benefit cost	4.0			4.7			0.3		0.4		2.4			0.3
Less: Amount paid by unconsolidated affiliates	0.8			1.3			—		—		0.4			0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.2		$	3.4		$	0.3	$	0.4	$	2.0		$	0.2

(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$5.5 millionand$4.0 millionof net periodic benefit cost recognizedduring thethree months endedMarch 31, 2017and2016, respectively, OG&E recognized the following:

• an increase in pension expense during thethree months endedMarch 31, 2017 and 2016of$2.9 millionand$2.3 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1); and

• an increase in postretirement medical expense in the three months endedMarch 31, 2017 and 2016 of $1.1 million and $2.0 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 for regulatory liability (see Note 1).

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

	Three Months Ended
	March 31,
(In millions)	2017		2016
Capitalized portion of net periodic pension benefit cost	$	1.0	$	1.2
Capitalized portion of net periodic postretirement benefit cost	0.7		0.1

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Report of Business Segments (Tables)

3 Months Ended

Mar. 31, 2017

Segment Reporting [Abstract]

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

The following tables summarize the results of the Company's business segments during the three months endedMarch 31, 2017 and 2016.

Three Months Ended March 31, 2017	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	456.0	$	—		$	—		$	—		$	456.0
Cost of sales	208.7		—			—			—			208.7
Other operation and maintenance	126.1		0.1			(2.2		)	—			124.0
Depreciation and amortization	54.7		—			0.9			—			55.6
Taxes other than income	22.3		0.2			1.4			—			23.9
Operating income (loss)	44.2		(0.3		)	(0.1		)	—			43.8
Equity in earnings of unconsolidated affiliates	—		35.6			—			—			35.6
Other income (expense)	12.9		0.1			(1.3		)	(0.1		)	11.6
Interest expense	33.6		—			1.5			(0.1		)	35.0
Income tax expense (benefit)	7.3		15.4			(2.7		)	—			20.0
Net income (loss)	$	16.2	$	20.0		$	(0.2	)	$	—		$	36.0
Investment in unconsolidated affiliates	$	—	$	1,158.9		$	—		$	—		$	1,158.9
Total assets	$	8,950.9	$	1,521.2		$	91.1		$	(428.3	)	$	10,134.9

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

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Summary of Significant Accounting Policies Equity Ownership (Details)	Mar. 31, 2017
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		Mar. 31, 2017	Dec. 31, 2016
Schedule of Regulatory Assets and Liabilities [Line Items]
Fuel clause under recoveries		$ 73.4	$ 51.3
Current Regulatory Assets		142.2	121.8
Non-Current Regulatory Assets		403.1	404.8
Current Regulatory Liabilities		13.4	12.3
Non-Current Regulatory Liabilities		306.7	299.7
Other Regulatory Liability [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Liabilities	[1]	13.4	12.3
Non-Current Regulatory Liabilities		1.5	1.4
Accrued removal obligations, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		268.6	262.8
Pension tracker
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Liabilities		36.6	35.5
Oklahoma demand program rider under recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	45.6	51.0
Other Regulatory Asset [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	8.6	9.5
Non-Current Regulatory Assets		16.8	17.6
Benefit obligations regulatory asset
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		228.9	232.6
Income taxes recoverable from customers, net
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		65.6	62.3
Smart Grid
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		38.2	43.2
Deferred storm expenses
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		40.5	35.7
Unamortized loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [Line Items]
Non-Current Regulatory Assets		13.1	13.4
SPP Cost Tracker Rider Under Recovery [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Current Regulatory Assets	[2]	$ 14.6	$ 10.0

[1] Included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.

[2] 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	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at January 1	$ 69.6	$ 63.3
Accretion expense	0.7	0.7
Balance at March 31	$ 70.3	$ 64.0

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Summary of Significant Accounting Policies Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (28.7)	$ (34.7)	$ (29.3)	$ (35.1)
Amounts reclassified from accumulated other comprehensive income (loss)	0.6	0.4
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	(31.5)	(38.4)	(32.1)	(39.2)
Amounts reclassified from accumulated other comprehensive income (loss)	0.6	0.8
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	2.7	2.5	2.7	2.5
Amounts reclassified from accumulated other comprehensive income (loss)	0.0	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
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	0.0	1.1	$ 0.0	$ 1.5
Amounts reclassified from accumulated other comprehensive income (loss)	$ 0.0	$ (0.4)

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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
		Mar. 31, 2017	Mar. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ (0.6)	$ (0.4)
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]	(1.0)	(1.2)
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		(0.4)	(0.4)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		(0.6)	(0.8)
Other Postretirement Benefit Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax	[1]	0.0	0.6
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, before Tax		0.0	0.6
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Tax		0.0	0.2
Amounts reclassified from accumulated other comprehensive income (loss), net of tax		$ 0.0	$ 0.4

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

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

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Investment in Unconsolidated Affiliates (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	May 01, 2013
Expected Settlement Charge	$ 20.9
Limited Partner Units Owned	111.0
Distribution Made to Limited Partner, Distributions Declared, Per Unit	$ 0.31800
Equity in earnings of unconsolidated affiliates	$ 35.6	$ 28.3
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	736.6		$ 743.7
Enogex LLC [Member]
Percentage of Enogex LLC Contributed				100.00%
Increase in fair value of net assets				$ 2,200.0
Enable Midstream Partners [Member]
Distributions from unconsolidated affiliates	$ 35.3	$ 35.3
OGE Holdings [Member]
Subordinated Units Held by Limited Partners of the LLC or LP.	68.2
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	25.70%	26.30%

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Investment in Unconsolidated Affiliates Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 5.8		$ 2.5
Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	2.2	$ 2.3
Operating Costs Charged [Member] | Enable Midstream Partners [Member] | OGE Energy [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	0.8	1.3
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	10.0	8.3
Natural Gas Transportation [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	8.8	8.8
Natural Gas Purchases [Member] | Enable Midstream Partners [Member] | OG&E [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	(0.4)	$ 1.5
Excluding Fuel Purchases [Member]
Related Party Transaction [Line Items]
Accounts receivable - unconsolidated affiliates	$ 5.9		$ 2.7

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Investment in Unconsolidated Affiliates Summarized Balance Sheet Information of Equity Method Investment (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Summarized Balance Sheet Information of Equity Method Investment [Abstract]
Current assets	$ 375.0	$ 396.0
Non-current assets	10,786.0	10,816.0
Current liabilities	279.0	362.0
Non-current liabilities	$ 3,111.0	$ 3,056.0

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Investment in Unconsolidated Affiliates Summarized Income Statement of Equity Method Investment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Schedule of Equity Method Investments [Line Items]
Operating revenues	$ 666.0	$ 509.0
Cost of natural gas and natural gas liquids	308.0	195.0
Operating income	140.0	103.0
Net income	$ 110.8	$ 86.0

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Investment in Unconsolidated Affiliates Reconciliation of Equity in Earnings of Unconsolidated Affiliates (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Net income	$ 110.8	$ 86.0
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	736.6		$ 743.7
Timing Differences Related to Equity Method Investee Net Income	0.0	(11.7)
Net Income Used to Calculate Equity in Earnings	110.8	74.3
Proportionate Unconsolidated Affiliate Net Income	28.5	19.5
OGE Energy's share of Enable net income	28.5	21.3
Amortization of basis difference	2.8	2.9
Elimination of Enable fair value step up	4.3	4.1
Equity in earnings of unconsolidated affiliates	$ 35.6	$ 28.3
OGE Holdings [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	25.70%	26.30%
OGE Energy [Member]
Reconciliation of Equity in Earnings of Unconsolidated Affiliates [Line Items]
Goodwill, Impairment Loss	$ 0.0	$ (1.8)

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Fair Value Measurements Carrying and Fair Value Amounts (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
OG&E Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	$ 2,683,000,000	$ 2,385,500,000
Long-Term Debt, Fair Value	2,941,500,000	2,657,200,000
OG&E Industrial Authority Bonds [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	135,400,000	135,400,000
Long-Term Debt, Fair Value	135,400,000	135,400,000
OG&E Tinker Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	9,800,000	9,900,000
Long-Term Debt, Fair Value	9,300,000	9,500,000
OGE Energy Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, Carrying Amount	99,800,000	99,700,000
Long-Term Debt, Fair Value	100,000,000	99,900,000
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

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Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Stock-Based Compensation Activity
Income tax benefit	$ 0.8	$ 0.6
Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 2.1	1.7
Total Shareholder Return [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	260,570
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 41.77
Performance Units Related to Earnings Per Share [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	86,857
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 34.95
Restricted Stock [Member]
Stock-Based Compensation Activity
Compensation expense	$ 0.0	0.0
Stock Compensation Plan [Member]
Stock-Based Compensation Activity
Compensation expense	2.1	1.7
Total Shareholder Return [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	1.5	1.1
Performance Units Related to Earnings Per Share [Member] | Performance Shares [Member]
Stock-Based Compensation Activity
Compensation expense	$ 0.6	$ 0.6

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Common Equity Automatic Dividend Reinvestment and Stock Purchase Plan (Details) - shares	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Automatic Dividend Reinvestment and Stock Purchase Plan [Member]
Stock Issued During Period, Shares, New Issues	0	0

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Common Equity Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Equity [Abstract]
Net income	$ 36.0	$ 25.2
Basic average common shares outstanding	199.7	199.7
Contingently issuable shares (performance and restricted stock units)	0.3	0.0
Diluted average common shares outstanding	200.0	199.7
Earnings Per Share, Basic and Diluted [Abstract]
Basic Earnings Per Average Common Share	$ 0.18	$ 0.13
Diluted Earnings Per Average Common Share	$ 0.18	$ 0.13
Anti-dilutive shares excluded from earnings per share calculation	0.0	0.0

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Long-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
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	0.65%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2025 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.65%
Minimum [Member] | Redeemable during the next 12 months | Muskogee Industrial Authority Bond Due 2027 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.66%
Maximum [Member] | Redeemable during the next 12 months | Garfield Industrial Authority Bond [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	0.95%
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	0.90%
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	0.95%
Senior Notes [Member] | OG&E [Member]
Debt Instrument [Line Items]
Long term debt	$ 300.0
Senior Notes [Member] | OG&E [Member] | Series due April 1, 2047 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.15%
Long term debt	$ 300.0
Debt Instrument, Maturity Date	Apr. 01, 2047
Senior Notes [Member] | OG&E [Member] | Series Due July 15, 2017 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Long term debt	$ 125.0
Debt Instrument, Maturity Date	Jul. 15, 2017

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Short-Term Debt and Credit Facilities (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Short-term debt		$ 128.2	$ 236.2
Line of Credit Facility [Abstract]
Aggregate Commitment		900.0
Amount Outstanding	[1]	$ 130.0
Weighted Average Interest Rate		1.214%
Ratio of Consolidated Debt to Consolidated Capitalization		65.00%
OGE Energy [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 450.0
OGE Energy [Member]
Line of Credit Facility [Abstract]
Amount Outstanding	[1],[2]	$ 128.2
Weighted Average Interest Rate	[2],[3]	1.219%
Maturity	[2]	Mar. 08, 2022
OG&E [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Current Borrowing Capacity	[4]	$ 450.0
Line of Credit Facility [Abstract]
Aggregate Commitment		600.0
Letters of Credit Outstanding, Amount	[1],[4]	$ 1.8
Weighted Average Interest Rate	[3],[4]	0.95%
Maturity	[4]	Mar. 08, 2022
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
Debt Restriction Maximum Letters of Credit		$ 100.0
Available Optional Increase of Borrowing Capacity in Credit Facility		150.0
Acceleration of Debt [Member] | OG&E [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		100.0
Uninsured Judgements [Member] | OGE Energy [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		100.0
Uninsured Judgements [Member] | OG&E [Member]
Line of Credit Facility [Abstract]
Acceleration of Indebtedness of Credit Facility		$ 100.0

[1] Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2017.

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

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

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

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Retirement Plans and Postretirement Benefit Plans (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Net periodic benefit cost (net of unconsolidated affiliates)		$ 5.5	$ 4.0
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		4.2	4.4
Interest cost		6.5	6.6
Expected return on plan assets		(10.7)	(10.5)
Amortization of net loss		4.0	4.2
Amortization of unrecognized prior service cost	[1]	0.0	0.0
Total net periodic benefit cost		4.0	4.7
Less: Amount paid by unconsolidated affiliates		0.8	1.3
Net periodic benefit cost (net of unconsolidated affiliates)	[2]	3.2	3.4
Capitalized Portion of Net Periodic Benefit Cost		1.0	1.2
Other Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		0.1	0.1
Interest cost		0.1	0.1
Expected return on plan assets		0.0	0.0
Amortization of net loss		0.1	0.2
Amortization of unrecognized prior service cost	[1]	0.0	0.0
Total net periodic benefit cost		0.3	0.4
Less: Amount paid by unconsolidated affiliates		0.0	0.0
Net periodic benefit cost (net of unconsolidated affiliates)	[2]	0.3	0.4
Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		0.2	0.3
Interest cost		2.2	2.3
Expected return on plan assets		(0.6)	(0.6)
Amortization of net loss		0.6	0.5
Amortization of unrecognized prior service cost		0.0	(2.2)
Total net periodic benefit cost		2.4	0.3
Less: Amount paid by unconsolidated affiliates		0.4	0.1
Net periodic benefit cost (net of unconsolidated affiliates)		2.0	0.2
Capitalized Portion of Net Periodic Benefit Cost		0.7	0.1
OKLAHOMA
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements		2.9	2.3
OKLAHOMA | Postretirement Benefit Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Additional Pension Expense to Meet State Requirements		$ 1.1	$ 2.0

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

[2] In addition to the $5.5 million and $4.0 million of net periodic benefit cost recognized during the three months ended March 31, 2017 and 2016, respectively, OG&E recognized the following:•an increase in pension expense during the three months ended March 31, 2017 and 2016 of $2.9 million and $2.3 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction, which are included in the pension tracker regulatory liability (see Note 1); and •an increase in postretirement medical expense in the three months ended March 31, 2017 and 2016 of $1.1 million and $2.0 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 for regulatory liability (see Note 1).

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Report of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating revenues	$ 456.0	$ 433.1
Cost of sales	208.7	177.9
Other operation and maintenance	124.0	113.9
Depreciation and amortization	55.6	78.5
Taxes other than income	23.9	24.9
OPERATING INCOME	43.8	37.9
Equity in earnings of unconsolidated affiliates	35.6	28.3
Other income (expense)	11.6	5.5
Interest expense	35.0	36.3
Income tax expense (benefit)	20.0	10.2
Net income (loss)	36.0	25.2
Investment in unconsolidated affiliates	1,158.9	1,187.4	$ 1,158.6
Total assets	10,134.9	9,523.3	$ 9,939.6
Electric Utility [Member]
Segment Reporting Information [Line Items]
Operating revenues	456.0	433.1
Cost of sales	208.7	177.9
Other operation and maintenance	126.1	116.3
Depreciation and amortization	54.7	76.7
Taxes other than income	22.3	23.6
OPERATING INCOME	44.2	38.6
Equity in earnings of unconsolidated affiliates	0.0	0.0
Other income (expense)	12.9	5.3
Interest expense	33.6	35.5
Income tax expense (benefit)	7.3	2.3
Net income (loss)	16.2	6.1
Investment in unconsolidated affiliates	0.0	0.0
Total assets	8,950.9	8,288.5
Natural Gas Midstream Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0
Cost of sales	0.0	0.0
Other operation and maintenance	0.1	0.2
Depreciation and amortization	0.0	0.0
Taxes other than income	0.2	0.0
OPERATING INCOME	(0.3)	(0.2)
Equity in earnings of unconsolidated affiliates	35.6	28.3
Other income (expense)	0.1	0.0
Interest expense	0.0	0.0
Income tax expense (benefit)	15.4	10.1
Net income (loss)	20.0	18.0
Investment in unconsolidated affiliates	1,158.9	1,187.4
Total assets	1,521.2	1,467.9
Other Operations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0
Cost of sales	0.0	0.0
Other operation and maintenance	(2.2)	(2.6)
Depreciation and amortization	0.9	1.8
Taxes other than income	1.4	1.3
OPERATING INCOME	(0.1)	(0.5)
Equity in earnings of unconsolidated affiliates	0.0	0.0
Other income (expense)	(1.3)	0.3
Interest expense	1.5	0.9
Income tax expense (benefit)	(2.7)	(2.2)
Net income (loss)	(0.2)	1.1
Investment in unconsolidated affiliates	0.0	0.0
Total assets	91.1	98.7
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0
Cost of sales	0.0	0.0
Other operation and maintenance	0.0	0.0
Depreciation and amortization	0.0	0.0
Taxes other than income	0.0	0.0
OPERATING INCOME	0.0	0.0
Equity in earnings of unconsolidated affiliates	0.0	0.0
Other income (expense)	(0.1)	(0.1)
Interest expense	(0.1)	(0.1)
Income tax expense (benefit)	0.0	0.0
Net income (loss)	0.0	0.0
Investment in unconsolidated affiliates	0.0	0.0
Total assets	(428.3)	(331.8)
OGE Energy [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss	$ 0.0	$ (1.8)

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Rate Matters and Regulation Rate Matters and Regulation (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Dry Scrubber Project [Member]
Estimated Environmental Capital Costs		$ 547.5
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		281.6
Mustang Modernization [Member]
Estimated Environmental Capital Costs		424.9
Public Utilities, Property, Plant and Equipment, Construction Work in Progress		231.8
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
Public Utilities, Interim Rate Increase (Decrease), Amount		69.5
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 8.8
Public Utilities, Approved Return on Equity, Percentage	9.50%
Approved Depreciation Reduction from ALJ Recommendation	$ 28.6
ALJ Depreciation Recommendation	$ 36.4
Approved Recovery of Short-term Incentive Comp	50.00%
Approved Recovery of Long-term Incentive Comp	0.00%
ARKANSAS
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 16.5
Public Utilities, Requested Return on Equity, Percentage		10.25%
Investments Since Last Rate Case		$ 3,000.0
Settlement of Rate Increase	$ 7.1
Settlement of Return on Equity, Percentage	9.50%
Settlement of Equity Capital Structure, Percentage	50.00%
Administrative Law Judge [Member]
Recommended Return on Equity		9.87%
Recommended Capital Structure, Equity Percentage		53.00%
Recommended Capital Structure, Debt Percentage		47.00%
Recommended Increase (Decrease) in Revenue		$ 40.7