Edgar Filing: OGE ENERGY CORP.

Q2 2015 OGE Energy 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)



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

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

405-553-3000

(Registrant's telephone number, including area code)

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

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

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



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

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

At June 30, 2015, there were 199,685,162 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2015

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	39

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

GLOSSARY OF TERMS

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



Abbreviation	Definition
2014 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2014
ALJ	Administrative Law Judge
APSC	Arkansas Public Service Commission
ArcLight	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ASU	Financial Accounting Standards Board Accounting Standards Update
BART	Best available retrofit technology
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
CO2	Carbon dioxide
Company	OGE Energy, collectively with its subsidiaries
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
Enable	Enable Midstream Partners, LP, partnership between OGE Energy, the ArcLight group and CenterPoint Energy, Inc. formed to own and operate the midstream businesses of OGE Energy and CenterPoint
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings, LLC (prior to May 1, 2013)
Enogex LLC	Enogex LLC, collectively with its subsidiaries (effective July 30, 2013, the name was changed to Enable Oklahoma Intrastate Transmission, LLC)
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIP	Federal implementation plan
GAAP	Accounting principles generally accepted in the United States
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 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019
MW	Megawatt
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NO_X	Nitrogen oxide
OCC	Oklahoma Corporation Commission
Off-system sales	Sales to other utilities and power marketers
OG&E	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy, parent company of Enogex Holdings (prior to May 1, 2013) and 26.3 percent owner of Enable Midstream Partners
Pension Plan	Qualified defined benefit retirement plan
PUD	Public Utility Division of the Oklahoma Corporation Commission
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SESH	Southeast Supply Header, LLC
SIP	State implementation plan
SO₂	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

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," are forward-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 materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in "Item 1A. Risk Factors" in the Company's 2014 Form 10-K and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, 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 of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms as well as inflation rates and monetary fluctuations;


•	prices and availability of electricity, coal, natural gas and 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 regions Enable serves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable's interstate pipelines;


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


•	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 by the Company;


•	unusual weather;


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


•	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 enters the Company's markets;


•	environmental laws and regulations that may impact the Company's operations;


•	changes in accounting standards, rules or guidelines;


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


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


•	advances in technology;


•	creditworthiness of suppliers, customers and other contractual parties;


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


•	other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in "Item 1A. Risk Factors" and in Exhibit 99.01 to the Company's 2014 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions except per share data)	2015			2014			2015			2014
OPERATING REVENUES	$	549.9		$	611.8		$	1,030.0		$	1,172.2
COST OF SALES	210.9			270.9			422.5			564.3
OPERATING EXPENSES
Other operation and maintenance	113.2			111.4			224.9			223.8
Depreciation and amortization	76.2			68.3			152.1			135.5
Taxes other than income	22.4			19.4			46.9			45.0
Total operating expenses	211.8			199.1			423.9			404.3
OPERATING INCOME	127.2			141.8			183.6			203.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates	28.2			39.3			59.9			87.2
Allowance for equity funds used during construction	1.7			0.8			3.2			1.9
Other income	5.6			3.1			10.5			4.5
Other expense	(2.2		)	(2.1		)	(3.2		)	(5.4		)
Net other income	33.3			41.1			70.4			88.2
INTEREST EXPENSE
Interest on long-term debt	37.0			37.8			73.9			72.9
Allowance for borrowed funds used during construction	(0.8		)	(0.5		)	(1.6		)	(1.1		)
Interest on short-term debt and other interest charges	1.8			2.1			3.1			3.5
Interest expense	38.0			39.4			75.4			75.3
INCOME BEFORE TAXES	122.5			143.5			178.6			216.5
INCOME TAX EXPENSE	35.0			42.7			47.9			66.4
NET INCOME	$	87.5		$	100.8		$	130.7		$	150.1
BASIC AVERAGE COMMON SHARES OUTSTANDING	199.6			199.2			199.6			199.0
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.6			200.0			199.6			199.8
BASIC EARNINGS PER AVERAGE COMMON SHARE	$	0.44		$	0.51		$	0.66		$	0.75
DILUTED EARNINGS PER AVERAGE COMMON SHARE	$	0.44		$	0.50		$	0.66		$	0.75
DIVIDENDS DECLARED PER COMMON SHARE	$	0.25000		$	0.22500		$	0.50000		$	0.45000

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2015			2014			2015			2014
Net income	$	87.5		$	100.8		$	130.7		$	150.1
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.6, $0.3, $1.4 and $0.6, respectively	0.8			0.5			1.2			0.9
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.2, $0.2, $0.4 and $0.3, respectively	0.4			0.3			0.6			0.5
Amortization of prior service cost, net of tax of ($0.2), ($0.3), ($0.5) and ($0.6), respectively	(0.5		)	(0.5		)	(0.9		)	(0.9		)
Amortization of deferred interest rate swap hedging losses, net of tax of $0.0, $0.0, $0.0 and $0.1, respectively	—			—			—			0.1
Other comprehensive income, net of tax	0.7			0.3			0.9			0.6
Comprehensive income	$	88.2		$	101.1		$	131.6		$	150.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	130.7		$	150.1
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	152.1			135.5
Deferred income taxes and investment tax credits, net	48.1			60.3
Equity in earnings of unconsolidated affiliates	(59.9		)	(87.2		)
Distributions from unconsolidated affiliates	68.9			76.5
Allowance for equity funds used during construction	(3.2		)	(1.9		)
Gain on disposition of assets	—			(0.2		)
Stock-based compensation	2.4			(7.0		)
Regulatory assets	2.5			(0.5		)
Regulatory liabilities	(2.0		)	(5.4		)
Other assets	4.5			(27.6		)
Other liabilities	(2.4		)	19.5
Change in certain current assets and liabilities
Accounts receivable, net	2.9			(8.0		)
Accounts receivable - unconsolidated affiliates	3.2			5.0
Accrued unbilled revenues	(30.8		)	(23.6		)
Fuel, materials and supplies inventories	(29.7		)	22.0
Fuel clause under recoveries	64.6			(55.9		)
Other current assets	(10.2		)	1.5
Accounts payable	(40.7		)	(61.0		)
Fuel clause over recoveries	1.6			(0.4		)
Other current liabilities	3.2			(9.9		)
Net Cash Provided from Operating Activities	305.8			181.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(227.7		)	(297.6		)
Proceeds from sale of assets	2.0			0.6
Net Cash Used in Investing Activities	(225.7		)	(297.0		)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid on common stock	(99.8		)	(89.5		)
Proceeds from long-term debt	—			246.5
Issuance of common stock	6.8			6.7
Payment of long-term debt	(0.1		)	(0.1		)
Increase (decrease) in short-term debt	7.5			(53.0		)
Net Cash (Used in) Provided from Financing Activities	(85.6		)	110.6
NET CHANGE IN CASH AND CASH EQUIVALENTS	(5.5		)	(4.6		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5.5			6.8
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	2.2

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2015		December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	5.5
Accounts receivable, less reserve of $1.2 and $1.6, respectively	185.9		188.8
Accounts receivable - unconsolidated affiliates	2.4		5.6
Accrued unbilled revenues	86.3		55.5
Income taxes receivable	16.3		16.0
Fuel inventories	89.4		58.5
Materials and supplies, at average cost	77.7		78.9
Deferred income taxes	173.1		191.4
Fuel clause under recoveries	3.7		68.3
Other	47.2		37.3
Total current assets	682.0		705.8
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,309.2		1,318.2
Other	73.3		70.1
Total other property and investments	1,382.5		1,388.3
PROPERTY, PLANT AND EQUIPMENT
In service	10,126.4		9,983.0
Construction work in progress	168.8		115.9
Total property, plant and equipment	10,295.2		10,098.9
Less accumulated depreciation	3,209.4		3,119.0
Net property, plant and equipment	7,085.8		6,979.9
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	404.8		411.5
Other	38.5		42.3
Total deferred charges and other assets	443.3		453.8
TOTAL ASSETS	$	9,593.6	$	9,527.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

(Unaudited)



(In millions)	June 30, 2015			December 31, 2014
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	105.5		$	98.0
Accounts payable	145.8			179.1
Dividends payable	49.9			49.9
Customer deposits	75.8			73.7
Accrued taxes	41.6			39.7
Accrued interest	42.9			43.0
Accrued compensation	32.9			38.2
Long-term debt due within one year	110.0			—
Fuel clause over recoveries	1.6			—
Other	56.3			51.7
Total current liabilities	662.3			573.3
LONG-TERM DEBT	2,645.4			2,755.3
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	310.8			315.5
Deferred income taxes	2,298.2			2,268.3
Regulatory liabilities	279.6			263.0
Other	111.3			108.0
Total deferred credits and other liabilities	2,999.9			2,954.8
Total liabilities	6,307.6			6,283.4
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,097.4			1,087.6
Retained earnings	2,229.1			2,198.2
Accumulated other comprehensive loss, net of tax	(40.5		)	(41.4		)
Total stockholders' equity	3,286.0			3,244.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,593.6		$	9,527.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

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, 2014	$	2.0	$	1,085.6		$	2,198.2		$	(41.4	)	$	3,244.4
Net income	—		—			130.7			—			130.7
Other comprehensive income, net of tax	—		—			—			0.9			0.9
Dividends declared on common stock	—		—			(99.8		)	—			(99.8		)
Issuance of common stock	—		6.8			—			—			6.8
Stock-based compensation	—		3.0			—			—			3.0
Balance at June 30, 2015	$	2.0	$	1,095.4		$	2,229.1		$	(40.5	)	$	3,286.0

Balance at December 31, 2013	$	2.0	$	1,071.6		$	1,991.7		$	(28.2	)	$	3,037.1
Net income	—		—			150.1			—			150.1
Other comprehensive income, net of tax	—		—			—			0.6			0.6
Dividends declared on common stock	—		—			(89.7		)	—			(89.7		)
Issuance of common stock	—		6.7			—			—			6.7
Stock-based compensation	—		(5.0		)	—			—			(5.0		)
Balance at June 30, 2014	$	2.0	$	1,073.3		$	2,052.1		$	(27.6	)	$	3,099.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

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 OGE Energy and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. OGE Energy generally uses the equity method of accounting for investments where its ownership interest is between 20 percent and 50 percent and has the ability to exercise significant influence.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through OG&E and are subject to regulation by the OCC, the APSC and the FERC. OG&E was incorporated in 1902 under the laws of the Oklahoma Territory, and is a wholly owned subsidiary of the Company. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. 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 currently 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. Enable's natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

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

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at June 30, 2015 and December 31, 2014, the results of its operations and cash flows for the three and six months ended June 30, 2015 and 2014, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the Company's operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company's 2014 Form 10-K.

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 actual or anticipated 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 actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refunded in future rates.

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



(In millions)	June 30, 2015		December 31, 2014
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	26.6	$	19.7
Fuel clause under recoveries	3.7		68.3
Other (A)	12.4		9.1
Total Current Regulatory Assets	$	42.7	$	97.1
Non-Current
Benefit obligations regulatory asset	$	254.2	$	261.1
Income taxes recoverable from customers, net	56.3		56.1
Smart Grid	43.8		43.9
Deferred storm expenses	17.0		17.5
Unamortized loss on reacquired debt	15.5		16.1
Other	18.0		16.8
Total Non-Current Regulatory Assets	$	404.8	$	411.5
Regulatory Liabilities
Current
Crossroads wind farm rider over recovery (B)	$	8.6	$	10.3
Smart Grid rider over recovery (B)	8.0		12.5
Fuel clause over recoveries	1.6		—
Other (B)	3.2		1.6
Total Current Regulatory Liabilities	$	21.4	$	24.4
Non-Current
Accrued removal obligations, net	$	256.4	$	248.1
Pension tracker	23.2		14.9
Total Non-Current Regulatory Liabilities	$	279.6	$	263.0


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


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

Investment in Unconsolidated Affiliate

OGE Energy'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, OGE Energy 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. As

discussed above, OGE Energy accounts for the 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. OGE Energy's maximum exposure to loss related to Enable is limited to OGE Energy's equity investment in Enable as presented on the Company's Condensed Consolidated Balance Sheet at June 30, 2015. The Company evaluates its equity method investment for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

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

Asset Retirement Obligation

The following table summarizes changes to the Company's asset retirement obligations during the six months ended June 30, 2015 and 2014.



	Six Months Ended June 30,
(In millions)	2015			2014
Balance at January 1	$	58.6		$	55.2
Liabilities settled (A)	(0.5		)	—
Accretion expense	1.3			1.3
Balance at June 30	$	59.4		$	56.5

(A) In 2015, asset retirement obligations were settled for the asbestos abatement at one of OGE's generating facilities.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive income (loss) attributable to OGE Energy during the six months ended June 30, 2015. All amounts below are presented net of tax.



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
(In millions)	Net loss			Prior service cost		Net loss			Prior service cost			Total
Balance at December 31, 2014	$	(36.8	)	$	0.1	$	(8.0	)	$	3.3		$	(41.4	)
Amounts reclassified from accumulated other comprehensive income (loss)	1.2			—		0.6			(0.9		)	0.9
Net current period other comprehensive income (loss)	1.2			—		0.6			(0.9		)	0.9
Balance at June 30, 2015	$	(35.6	)	$	0.1	$	(7.4	)	$	2.4		$	(40.5	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive income (loss) by the respective line items in net income during the three and six months ended June 30, 2015 and 2014.



Details about Accumulated Other Comprehensive Income (Loss) Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended						Six Months Ended
(In millions)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Losses on cash flow hedges
Interest rate swap	$	—		$	—		$	—		$	(0.2	)	Interest expense
	—			—			—			(0.2		)	Total before tax
	—			—			—			(0.1		)	Tax benefit
	$	—		$	—		$	—		$	(0.1	)	Net of tax

Amortization of defined benefit pension and restoration of retirement income plan items
Actuarial losses	$	(1.4	)	$	(0.8	)	$	(2.6	)	$	(1.5	)	(A)
	(1.4		)	(0.8		)	(2.6		)	(1.5		)	Total before tax
	(0.6		)	(0.3		)	(1.4		)	(0.6		)	Tax benefit
	$	(0.8	)	$	(0.5	)	$	(1.2	)	$	(0.9	)	Net of tax

Amortization of postretirement benefit plan items
Actuarial losses	$	(0.6	)	$	(0.5	)	$	(1.0	)	$	(0.8	)	(A)
Prior service credit	0.7			0.8			1.4			1.5			(A)
	0.1			0.3			0.4			0.7			Total before tax
	—			0.1			0.1			0.3			Tax (benefit) expense
	$	0.1		$	0.2		$	0.3		$	0.4		Net of tax

Total reclassifications for the period	$	(0.7	)	$	(0.3	)	$	(0.9	)	$	(0.6	)	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

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. For public entities, 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 FASB decided, based on its outreach to various stakeholders and the forthcoming amendments to the new revenue standard, that a deferral is necessary to provide adequate time to effectively implement the new revenue standard. The Company is still determining the impact of this standard.

In April 2015, the FASB issued ASU 2015-03, "Interest - Imputation of Interest (Suptopic 835-30): Simplifying the Presentation of Debt Issuance Costs". The amendments in ASU 2015-03 require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments. The FASB issued the updated guidance as part of its initiative to reduce complexity in accounting standards, as it had received feedback that having different balance sheet presentation requirements for debt issuance costs and debt discount and premium created unnecessary complexity. On June 18, 2015, the SEC observer stated that given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to revolving debt arrangements, the SEC staff would not object to an entity deferring and presenting such costs as an asset and subsequently amortizing them ratably over the term of the revolving debt arrangement. For public

business entities, the amendments in this ASU are effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company will reflect the impacts of this ASU in the first quarter of 2016.


3.	Investment in Unconsolidated Affiliate and Related Party Transactions

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

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

On April 16, 2014, Enable completed an initial public offering of 25,000,000 common units resulting in Enable becoming a publicly traded Master Limited Partnership. In connection with Enable’s initial public offering, approximately 61.4 percent of OGE Holdings and CenterPoint’s common units were converted into subordinated units. As a result, following the initial public offering, OGE Holdings owned 42,832,291 common units and 68,150,514 subordinated units of Enable. Holders of subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordinated units will convert into common units when Enable has paid at least the minimum quarterly distribution for three years or paid at least 150 percent of the minimum quarterly distribution for one year.

On April 24, 2015, Enable announced a quarterly dividend distribution of $0.31250 per unit on its outstanding common and subordinated units, representing an increase of approximately 1.2 percent over the prior quarter distribution. Enable's gross margins are affected by commodity price movements. Based on forward commodity prices, Enable expects to see a decrease in producer activity that will affect its future distribution growth rate. 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. OGE Holdings is entitled to 60 percent of those “incentive distributions.” In certain circumstances, the general partner will have 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.

On July 22, 2015, Enable announced a quarterly dividend distribution of $0.31600 per unit on its outstanding common and subordinated units, representing an increase of approximately 1.1 percent over the prior quarter distribution. Distributions received from Enable were $34.6 million and $44.0 million for the three months ended June 30, 2015 and 2014, respectively, and $68.9 million and $76.5 million for the six months ended June 30, 2015 and 2014, respectively.

At June 30, 2015, OGE Energy held 26.3 percent of the limited partner interests in Enable.

Related Party Transactions

Operating costs charged and related party transactions between the Company and its affiliate, Enable, since its formation on May 1, 2013 are discussed below. Prior to May 1, 2013, operating costs charged and related party transactions between the Company and Enogex Holdings were eliminated in consolidation. OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013.

On May 1, 2013, OGE Energy and Enable entered into a Services Agreement, Employee Transition Agreement, and other agreements whereby OGE Energy 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. The support services automatically extend year-to-year at the end of the initial term, unless terminated by Enable with at least 90 days’ notice. Enable may terminate the initial support services at any time with 180 days' notice if approved by the board of Enable's general partner. Under these agreements, OGE Energy charged operating costs to Enable of $2.5 million and $3.8 million (which results in a corresponding reduction to OGE Energy's operations and maintenance expense) for the three months ended June 30, 2015 and 2014, respectively, and $5.3 million and $9.8 million for the six months ended June 30, 2015 and 2014, respectively. OGE Energy 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 and Enable are allocated either as overhead based primarily on labor costs or using the "Distrigas" method.

Additionally, OGE Energy agreed to provide seconded employees to Enable to support its operations for an initial term ending on December 31, 2014. In October, 2014, CenterPoint, OGE Energy and Enable agreed to continue the secondment to Enable of 192 OGE Energy employees that participate in OGE Energy's defined benefit and retirement plans beyond December 31, 2014. OGE Energy billed Enable for reimbursement of $8.1 million and $22.2 million during the three months ended June 30, 2015 and June 30, 2014, respectively, and $18.1 million and $53.0 million during the six months ended June 30, 2015 and June 30, 2014, respectively, under the Transitional Seconding Agreement for employment costs.

OGE Energy had accounts receivable from Enable of $2.4 million and $5.6 million as of June 30, 2015 and December 31, 2014, respectively, for amounts billed for transitional services, including the cost of seconded employees.

Related Party Transactions with Enable

OG&E entered into a new contract with Enable to provide transportation services effective May 1, 2014 which eliminated the natural gas storage services. 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 its affiliate, Enable, during the three and six months ended June 30, 2015 and 2014.



	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2015		2014			2015		2014
Operating Revenues:
Electricity to power electric compression assets	$	3.6	$	3.3		$	6.7	$	6.0
Cost of Sales:
Natural gas transportation services	$	8.7	$	8.7		$	17.5	$	17.4
Natural gas storage services	—		1.1			—		4.4
Natural gas purchases	2.1		(1.4		)	4.6		3.5

Summarized Financial Information of Enable

Summarized unaudited financial information for 100 percent of Enable is presented below at June 30, 2015 and December 31, 2014 and for the six months ended June 30, 2015 and June 30, 2014.



Balance Sheet	June 30, 2015		December 31, 2014
	(In millions)
Current assets	$	415	$	438
Non-current assets	11,765		11,399
Current liabilities	834		671
Non-current liabilities	2,611		2,344



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Income Statement	2015		2014		2015		2014
	(In millions)
Operating revenues	$	590	$	827	$	1,206	$	1,828
Cost of sales	277		478		569		1,111
Operating income	93		139		197		301
Net income	77		120		168		269

The formation of Enable was considered a business combination, and CenterPoint Midstream was the acquirer of Enogex Holdings for accounting purposes. Under this method, the fair value of the consideration paid by CenterPoint Midstream 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.

OGE Energy recorded equity in earnings of unconsolidated affiliates of $28.2 million and $39.3 million and $59.9 million and $87.2 million for the three and six months ended June 30, 2015 and 2014, respectively. Equity in earnings of unconsolidated affiliates includes OGE Energy's share of Enable earnings adjusted for the amortization of the basis difference of OGE Energy's original investment in Enogex and its underlying equity in net assets of Enable. The basis difference is the result of the initial contribution of Enogex to Enable in May 2013, and subsequent issuances of equity by Enable, including the IPO in April 2014 and the issuance of common units for the acquisition of CenterPoint's 24.95 percent interest in SESH. The basis difference is being amortized over approximately 30 years, the average life of the assets to which the basis difference is attributed. Equity in earnings of unconsolidated affiliates is also adjusted for the elimination of the Enogex Holdings fair value adjustments, as described above.

The difference between the Company's investment in Enable and its underlying equity in the net assets of Enable was $1.0 billion as of June 30, 2015.

The following table reconciles OGE Energy's equity in earnings of its unconsolidated affiliates for the three and six months ended June 30, 2015 and 2014.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	2015		2014		2015		2014
(In millions)
OGE's share of Enable Net Income	$	20.6	$	32.2	$	44.4	$	74.7
Amortization of basis difference	3.6		3.4		7.1		7.0
Elimination of Enogex Holdings fair value and other adjustments	4.0		3.7		8.4		5.5
OGE's Equity in earnings of unconsolidated affiliates	$	28.2	$	39.3	$	59.9	$	87.2


4.	Fair Value Measurements

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

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

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

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

The Company had no financial instruments measured at fair value on a recurring basis at June 30, 2015 and December 31, 2014.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at June 30, 2015 and December 31, 2014.



	June 30, 2015				December 31, 2014
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,509.9	$	2,811.6	$	2,509.7	$	2,957.7
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.1		9.1		10.2		10.3
OGE Energy Senior Notes	100.0		99.9		100.0		99.9

The Company's long-term debt is recorded at the carrying amount. 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 except for the Tinker Debt which fair value was based on calculating the net present value of the monthly payments discounted by the Company's current borrowing rate and is classified as Level 3 in the fair value hierarchy.


5.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and six months ended June 30, 2015 and 2014 related to the Company's performance units and restricted stock.



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2015		2014		2015		2014
Performance units
Total shareholder return	$	1.9	$	1.9	$	3.8	$	3.9
Earnings per share	0.6		0.4		1.1		2.1
Total performance units	2.5		2.3		4.9		6.0
Restricted stock	0.1		—		0.1		0.1
Total compensation expense	2.6		2.3		5.0		6.1
Less: Amount paid by unconsolidated affiliates	0.2		0.7		0.5		1.9
Net compensation expense	$	2.4	$	1.6	$	4.5	$	4.2
Income tax benefit	$	1.0	$	0.6	$	1.8	$	1.6

The Company has issued new shares to satisfy restricted stock grants and payouts of earned performance units. During the three and six months ended June 30, 2015, there were 172 shares and 80,953 shares, respectively, of new common stock issued pursuant to the Company's stock incentive plans related to restricted stock grants (net of forfeitures) and payouts of earned performance units. During the three and six months ended June 30, 2015, there were 91 shares and 1,070 shares, respectively, of restricted stock returned to the Company to satisfy tax liabilities.


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 to 2011 or state and local tax examinations by tax authorities for years prior to 2010. 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 claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E continues to amortize its Federal investment tax credits on a ratable basis throughout the year. 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.

As previously reported, OG&E has determined that a portion of certain Oklahoma investment tax credits previously recognized but not yet utilized may not be available for utilization in future years. During the second quarter of 2015, OG&E recorded an additional reserve for this item of $1.3 million ($0.9 million after the federal tax benefit) related to the same Oklahoma investment tax credits generated in the current year but not yet utilized due to management's determination that it is more likely than not that it will be unable to utilize these credits.


7.	Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 111,004 shares and 200,872 shares of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and six months ended June 30, 2015 and received proceeds of $3.5 million and $6.8 million, respectively. The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital requirements or working capital needs. At June 30, 2015, there were 4,790,940 shares of unissued common stock reserved for issuance under the Company's Automatic Dividend Reinvestment and Stock Purchase Plan.

Earnings Per Share

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



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions except per share data)	2015		2014		2015		2014
Net Income	$	87.5	$	100.8	$	130.7	$	150.1
Average Common Shares Outstanding
Basic average common shares outstanding	199.6		199.2		199.6		199.0
Effect of dilutive securities:
Contingently issuable shares (performance and restricted stock units)	—		0.8		—		0.8
Diluted average common shares outstanding	199.6		200.0		199.6		199.8
Basic Earnings Per Average Common Share	$	0.44	$	0.51	$	0.66	$	0.75
Diluted Earnings Per Average Common Share	$	0.44	$	0.50	$	0.66	$	0.75
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—


8.	Long-Term Debt

At June 30, 2015, the Company was in compliance with all of its debt agreements.

OG&E Industrial Authority Bonds

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



SERIES			DATE DUE	AMOUNT
				(In millions)
0.05%	-	0.13%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.06%	-	0.19%	Muskogee Industrial Authority, January 1, 2025	32.4
0.05%	-	0.14%	Muskogee Industrial Authority, June 1, 2027	56.0
Total (redeemable during next 12 months)				$	135.4

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


9.	Short-Term Debt and Credit Facilities

The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. The short-term debt balance was $105.5 million and $98.0 million at June 30, 2015 and December 31, 2014, respectively. The following table provides information regarding the Company's revolving credit agreements at June 30, 2015.



	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0	$	105.5	0.48	%	(D)	December 13, 2018
OG&E (C)	400.0		1.9		0.95	%	(D)	December 13, 2018
Total	$	1,150.0	$	107.4	0.49	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2015.


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


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


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

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 ratings 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 by itself would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash 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 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016.


10.	Retirement Plans and Postretirement Benefit Plans

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

Net Periodic Benefit Cost



	Pension Plan												Restoration of Retirement Income Plan
	Three Months Ended						Six Months Ended						Three Months Ended				Six Months Ended
	June 30,						June 30,						June 30,				June 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)			2015 (B)		2014 (B)		2015 (C)		2014 (C)
Service cost	$	3.4		$	3.3		$	7.9		$	7.6		$	0.2	$	0.2	$	0.6	$	0.5
Interest cost	6.6			7.1			13.0			14.1			0.1		0.1		0.3		0.3
Expected return on plan assets	(11.7		)	(10.2		)	(23.5		)	(22.7		)	—		—		—		—
Amortization of net loss	5.4			3.6			9.7			7.1			0.2		0.1		0.3		0.1
Amortization of unrecognized prior service cost (A)	0.1			0.5			0.2			0.9			0.1		0.1		0.1		0.1
Total net periodic benefit cost	3.8			4.3			7.3			7.0			0.6		0.5		1.3		1.0
Less: Amount paid by unconsolidated affiliates	1.0			0.9			2.1			1.7			0.1		0.1		0.1		0.1
Net periodic benefit cost (net of unconsolidated affiliates)	$	2.8		$	3.4		$	5.2		$	5.3		$	0.5	$	0.4	$	1.2	$	0.9


(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 $3.3 million and $3.8 million of net periodic benefit cost recognized during the three months ended June 30, 2015 and 2014, respectively, OG&E recognized an increase in pension expense during the three months ended June 30, 2015 and 2014 of $2.4 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).

(C)

In addition to the $6.4 million and $6.2 million of net periodic benefit cost recognized during the six months ended June 30, 2015 and 2014, respectively, OG&E recognized an increase in pension expense during the six months ended June 30, 2015 and 2014 of $5.4 million and $5.6 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).



	Postretirement Benefit Plans
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2015 (B)			2014 (B)			2015 (C)			2014 (C)
Service cost	$	0.3		$	0.7		$	0.8		$	1.6
Interest cost	2.5			2.9			5.1			5.7
Expected return on plan assets	(0.6		)	(0.6		)	(1.2		)	(1.2		)
Amortization of net loss	3.5			3.1			6.9			6.2
Amortization of unrecognized prior service cost (A)	(4.2		)	(4.2		)	(8.3		)	(8.3		)
Total net periodic benefit cost	1.5			1.9			3.3			4.0
Less: Amount paid by unconsolidated affiliates	0.3			0.4			0.6			0.7
Net periodic benefit cost (net of unconsolidated affiliates)	$	1.2		$	1.5		$	2.7		$	3.3


(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 $1.2 million and $1.5 million of net periodic benefit cost recognized during the three months ended June 30, 2015 and 2014, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended June 30, 2015 and 2014 of $1.5 million and $1.4 million, respectively, to maintain the allowable amount to be recovered for postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).


(C)	In addition to the $2.7 million and $3.3 million of net periodic benefit cost recognized during the six months ended June 30, 2015 and 2014, respectively, OG&E recognized an increase in postretirement medical expense during the six months ended June 30, 2015 and 2014 of $2.9 million and $2.6 million, respectively, to maintain the allowable amount to be recovered for

postretirement medical expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).



	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2015		2014		2015		2014
Capitalized portion of net periodic pension benefit cost	$	1.2	$	1.1	$	2.0	$	1.7
Capitalized portion of net periodic postretirement benefit cost	0.4		0.5		0.9		1.0


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. Other Operations primarily includes the operations of the holding company.

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

The following tables summarize the results of the Company's business segments during the three and six months ended June 30, 2015 and 2014.



Three Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	549.9	$	—		$	—		$	—		$	549.9
Cost of sales	210.9		—			—			—			210.9
Other operation and maintenance	115.6		0.2			(2.6		)	—			113.2
Depreciation and amortization	74.3		—			1.9			—			76.2
Taxes other than income	21.6		—			0.8			—			22.4
Operating income (loss)	127.5		(0.2		)	(0.1		)	—			127.2
Equity in earnings of unconsolidated affiliates	—		28.2			—			—			28.2
Other income (expense)	4.4		—			0.8			(0.1		)	5.1
Interest expense	37.3		—			0.8			(0.1		)	38.0
Income tax expense	25.6		10.0			(0.6		)	—			35.0
Net income (loss)	$	69.0	$	18.0		$	0.5		$	—		$	87.5
Investment in unconsolidated affiliates (at historical cost)	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,332.6	$	1,486.6		$	122.4		$	(348.0	)	$	9,593.6



Three Months Ended June 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	611.8	$	—		$	—		$	—		$	611.8
Cost of sales	270.9		—			—			—			270.9
Other operation and maintenance	115.0		0.4			(4.0		)	—			111.4
Depreciation and amortization	65.0		—			3.3			—			68.3
Taxes other than income	18.7		—			0.7			—			19.4
Operating income (loss)	142.2		(0.4		)	—			—			141.8
Equity in earnings of unconsolidated affiliates	—		39.3			—			—			39.3
Other income (expense)	1.2		—			0.6			—			1.8
Interest expense	37.5		—			1.9			—			39.4
Income tax expense	29.0		14.9			(1.2		)	—			42.7
Net income (loss)	$	76.9	$	24.0		$	(0.1	)	$	—		$	100.8
Investment in unconsolidated affiliates (at historical cost)	$	—	$	1,309.6		$	—		$	—		$	1,309.6
Total assets	$	7,908.0	$	1,371.8		$	141.0		$	(96.5	)	$	9,324.3



Six Months Ended June 30, 2015	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,030.0	$	—		$	—		$	—		$	1,030.0
Cost of sales	422.5		—			—			—			422.5
Other operation and maintenance	229.9		1.0			(6.0		)	—			224.9
Depreciation and amortization	148.1		—			4.0			—			152.1
Taxes other than income	44.7		—			2.2			—			46.9
Operating income (loss)	184.8		(1.0		)	(0.2		)	—			183.6
Equity in earnings of unconsolidated affiliates	—		59.9			—			—			59.9
Other income (expense)	7.3		—			3.3			(0.1		)	10.5
Interest expense	74.1		—			1.4			(0.1		)	75.4
Income tax expense	31.9		18.1			(2.1		)	—			47.9
Net income (loss)	$	86.1	$	40.8		$	3.8		$	—		$	130.7
Investment in unconsolidated affiliates (at historical cost)	$	—	$	1,309.2		$	—		$	—		$	1,309.2
Total assets	$	8,332.6	$	1,486.6		$	122.4		$	(348.0	)	$	9,593.6



Six Months Ended June 30, 2014	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,172.2	$	—		$	—		$	—		$	1,172.2
Cost of sales	564.3		—			—			—			564.3
Other operation and maintenance	232.1		0.4			(8.7		)	—			223.8
Depreciation and amortization	129.3		—			6.2			—			135.5
Taxes other than income	42.5		—			2.5			—			45.0
Operating income (loss)	204.0		(0.4		)	—			—			203.6
Equity in earnings of unconsolidated affiliates	—		87.2			—			—			87.2
Other income (expense)	1.6		—			(0.6		)	—			1.0
Interest expense	71.4		—			3.9			—			75.3
Income tax expense	36.6		33.4			(3.6		)	—			66.4
Net income (loss)	$	97.6	$	53.4		$	(0.9	)	$	—		$	150.1
Investment in unconsolidated affiliates (at historical cost)	$	—	$	1,309.6		$	—		$	—		$	1,309.6
Total assets	$	7,908.0	$	1,371.8		$	141.0		$	(96.5	)	$	9,324.3


12.	Commitments and Contingencies

Except as set forth below, in Note 13 and under "Environmental Laws and Regulations" in Item 2 of Part I and in Item 1 of Part II of this Form 10-Q, the circumstances set forth in Notes 14 and 15 to the Company's Consolidated Financial Statements included in the Company's 2014 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

Environmental Laws and Regulations

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

On July 8, 2013, the Department of Justice, filed a complaint against OG&E in United States District Court for the Western District of Oklahoma alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. The Sierra Club intervened in this proceeding. On September 6, 2013, OG&E filed a Motion to Dismiss the case. On January 15, 2015, U.S. District Judge Timothy DeGuisti dismissed the complaints filed by the EPA and Sierra Club. The Court held that it lacked subject matter jurisdiction over the Plaintiffs’ claims because Plaintiffs failed to present an actual “case or controversy” as required by Article III of the Constitution. The court also ruled in the alternative that, even if the Plaintiffs had presented a case or controversy, it would have nonetheless “decline[d] to exercise jurisdiction.” The EPA and the Sierra Club did not file an appeal of the Court’s ruling.

On August 12, 2013, the Sierra Club filed a separate complaint against OG&E in the United States District Court for the Eastern District of Oklahoma alleging that OG&E projects at Muskogee Unit 6 in 2008, were made without obtaining a prevention of significant deterioration permit and that the plant had exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks a permanent injunction preventing OG&E from operating the Muskogee generating plant. On March 4, 2014, the Eastern District dismissed the prevention of significant deterioration permit claim based on the statute of limitations, but allowed the opacity and particulate matter claims to proceed. To obtain the right to appeal this decision, the Sierra Club subsequently withdrew a Notice of Intent to Sue for additional Clean Air Act violations and asked the Eastern District to dismiss its remaining claims with prejudice. On August 27, 2014, the Eastern District granted the Sierra Club's request. The Sierra Club has filed a Notice of Appeal with the 10th Circuit where oral argument was held on March 18, 2015.

At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act, and OG&E expects to vigorously defend against the claims that have been asserted. If OG&E does not prevail in the remainder of the proceedings, the Sierra Club could seek to require OG&E to install additional pollution control equipment at Muskogee 6, including scrubbers, baghouses and selective catalytic reduction systems and pay fines and significant penalties as a result of the allegations. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for

civil penalties as much as $37,500 per day for each violation. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.

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 scrubber systems. The scrubbers are part of OG&E’s Environmental Compliance Plan and scheduled to be completed by 2019. More detail regarding the Environmental Plan can be found under the “Pending Regulatory Matters” in Note 13.

Clean Power Plan

On August 3, 2015, the EPA issued its final Clean Power Plan rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans for power plants in its state to meet the individual state targets established in the Clean Power Plan. The EPA has given states the option to develop compliance plans for annual rate-based reductions (lb/MWh) or mass-based tonnage limits for CO2. 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. The state plans are due in September 2016, subject to potential extensions of up to two years for final plan submission. The compliance period begins in 2022, and emission reductions will be phased in to 2030. The EPA also proposed a federal compliance plan to implement the Clean Power Plan in the event that an approvable state plan is not submitted to the EPA. OG&E is evaluating the Clean Power Plan rules and has not reached any final conclusions.

Other

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits or claims made by third parties, including governmental agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If, in management's opinion, the Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Condensed Consolidated Financial Statements. At the present time, based on 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 Note 15 to the Company's Consolidated Financial Statements included in the Company's 2014 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Arkansas Regulatory Developments

The State of Arkansas earlier in 2015 enacted two laws related to rate filings. Act 725, among other things, provides a public utility the option, to be exercised concurrently with the filing of a general rate application, to file notice of its intent to exercise its right for an annual formula rate review so as to provide a streamlined review of the utility’s rates to determine if adjustments in rates are justified. If the utility exercises such rights, rates may be adjusted if the earned return rate is 0.5 percent above or below the target return rate. This procedure is expected to reduce regulatory lag in Arkansas. Act 725 additionally allows for evidence to be presented, relative to the calculation of the return on common equity, comparing the requested return on common equity to approved returns on common equity for public utilities delivering similar services with corresponding risks within Arkansas and also in similar regulatory jurisdictions in the same general part of the country.

Act 1000 amends and clarifies existing interim rate requirements to expand the types of expenses that may be recorded and specifically authorize the recovery of allowance for funds used during construction. Act 1000 allows a public utility to file for an interim rate schedule through which it may recover investments and expenses, including allowance for funds used during construction, expended complying with legislative or administrative rules, regulations, or requirements related to the protection of the public, health, safety, or the environment. Rates are implemented at the time of filing of the interim rate schedule, subject to refund. As permitted by Act 1000, on May 8, 2015, OG&E filed an interim rate schedule to recover expenditures for the Arkansas portion of the low NOx burners made in order to comply with the Regional Haze rule for NOx.

Pending Regulatory Matters

Environmental Compliance Plan

On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance and Mustang Modernization Plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding.

As previously reported, on June 8, 2015 the ALJ issued his report on OG&E's application. While the ALJ in his report agrees that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s environmental compliance plan is the best approach, the ALJ makes various recommendations including, among others, that: (i) the OCC should not raise rates at this time; (ii) with respect to OG&E’s environmental compliance plan, the OCC should grant pre-approval of the estimated costs for new equipment as set by contract, including installation costs covered by a contract, but pre-approval of other equipment and installation costs that were still being negotiated at the end of the evidentiary hearing on April 8, 2015 should be deferred and may be considered in the next general rate case; (iii) the foregoing pre-approval is subject to the condition that the OCC should direct OG&E to issue requests for information for at least 200 MWs of wind power within thirty days of a final order; (iv) the OCC should postpone consideration of all other cost recovery issues until the next general rate case; (v) the OCC should direct the PUD Director to commence a general rate case; and (vi) the OCC should deny the Mustang Modernization Plan. OG&E filed exceptions to the ALJ's report in which OG&E set forth the various findings and recommendations that OG&E believes to be erroneous, including the ALJ’s refusal to recommend a recovery rider for OG&E environmental compliance plan and the ALJ’s recommendation that the OCC should deny the Mustang Modernization Plan. The OCC heard oral arguments on June 25, 2015 and took the case under advisement. On July 21, 2015, Commissioner Bob Anthony (one of the three commissioners on the OCC) issued his deliberation statement that was consistent with many parts of the ALJ Report, including the ALJ’s support of OG&E’s environmental compliance plan, the ALJ’s recommendation, as described above, to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other costs recovery issues until the next general rate case. OG&E cannot predict the outcome of this proceeding.

Oklahoma Demand Program Rider Review

In July 2012, OG&E filed an application with the OCC to recover certain costs associated with Demand Programs through the Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off peak hours during the months of May through October, by offering lower rates to those customers in the off peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers, by the reduction of more costly on-peak generation and the delay in adding new on-peak generation.

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

In March 2014, the Oklahoma PUD staff began their review of the Demand Program cost, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the Oklahoma PUD staff on the methodology to be used to calculate lost revenues associated with the SmartHours program and the amount of lost revenue for 2013, which totaled $10.1 million. The agreement also included utilizing the same methodology for calculating lost revenues for 2014, which would result in lost revenues for 2014 of $11.6 million.

In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues, in accordance with the agreement that it believed had been reached with the Oklahoma PUD staff.

In April 2015, the Oklahoma PUD staff filed an application, seeking an order from the OCC determining the proper calculation methodology for lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues. In the application, the Oklahoma PUD staff recommends the OCC approve the Oklahoma Public Utility

Division staff methodology for calculating lost revenues associated with the SmartHours program, which differs from the methodology that OG&E believes it had agreed upon and which would result in recovery of lost revenue for 2013 of only $4.9 million, a reduction of $5.2 million from the amount recorded by OG&E for 2013.

OG&E believes that the methodology agreed to in November 2014, is consistent with the 2012 OCC order, and believes that it is probable that it will recover the $10.1 million of lost revenues associated with 2013, and the $11.6 million associated with 2014. A hearing was held on June 30, 2015 and July 1, 2015. OG&E expects a commission ruling in the third quarter of 2015.

Fuel Adjustment Clause Review for Calendar Year 2013

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. On May 21, 2015, the ALJ recommended that the OCC find that OG&E's 2013 electric generation, purchased power and fuel procurement processes and costs were prudent, accurate and properly applied to customer billing statements. OG&E received an order to that effect from the OCC on June 17, 2015.

Fuel Adjustment Clause Review for Calendar Year 2014

On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs.

Oklahoma Rate Case Filing

On July 28, 2015 OG&E filed a notice of intent with the OCC to file a general rate case on or before November 30, 2015 based on a June 30, 2015 test year and to modify rates no later than 180 days from the date of filing the rate case. Among the matters OG&E expects the rate case to address are certain cost recovery riders, the retail portion of transmission expenditures made by OG&E since the last rate case, ad valorem taxes, depreciation rates, impact of the expiration of OG&E’s wholesale contracts and the costs associated with the SPP Integrated Market.

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

Introduction

On July 22, 2015, Enable announced a quarterly dividend distribution of $0.3160 per unit on its outstanding common and subordinated units, representing an increase of approximately 1.1 percent over the prior quarter distribution.

Overview

Company Strategy

The Company's mission, 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 infrastructure and meet individual customers' 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 relies on cash distributions from its investment in Enable to fund its capital needs and support future dividend growth. The cash distributions from Enable are expected to grow 3 percent to 7 percent in 2015 from the fourth quarter 2014 distribution. 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 maintaining strong regulatory and legislative relationships.

Summary of Operating Results

Three Months Ended June 30, 2015 as Compared to Three Months Ended June 30, 2014

Net income attributable to OGE Energy was $87.5 million, or $0.44 per diluted share, during the three months ended June 30, 2015 as compared to $100.8 million, or $0.50 per diluted share, during the same period in 2014. The decrease in net income attributable to OGE Energy of $13.3 million, or $0.06 per diluted share, during the three months ended June 30, 2015 as compared to the same period in 2014 was primarily due to:

•

a decrease in net income at OG&E of $7.9 million, or 10.3 percent, or $0.04 per diluted share of the Company's common stock, reflecting a decrease in gross margin related to lower wholesale transmission revenue and mild weather, an increase in depreciation expense due to additional assets being placed into service in 2014 and higher taxes other than income. Partially offsetting these items was an increase in gross margin related to an increase in customer growth, higher other income and a decrease in income tax expense; and


•	a decrease in net income attributable to OGE Holdings of $6.0 million, or $0.02 per diluted share of the Company's common stock, primarily due to lower average natural gas prices and lower NGLs prices.

These decreases were partially offset by an increase in net income attributable to OGE Energy of $0.6 million, primarily due to gains associated with the deferred compensation plan.

Six Months Ended June 30, 2015 as Compared to Six Months Ended June 30, 2014

Net income attributable to OGE Energy was $130.7 million, or $0.66 per diluted share, during the six months ended June 30, 2015 as compared to $150.1 million, or $0.75 per diluted share, during the same period in 2014. The decrease in net income attributable to OGE Energy of $19.4 million, or $0.09 per diluted share, during the six months ended June 30, 2015 as compared to the same period in 2014 was primarily due to:

•

a decrease in net income at OG&E of $11.5 million, or 11.8 percent, or $0.06 per diluted share of the Company's common stock, reflecting a decrease in gross margin related to milder weather during the six months ended June 2015 as compared to the same period in 2014, lower wholesale transmission revenue, an increase in depreciation expense due to additional assets being placed into service in 2014 and higher taxes other than income. Partially offsetting these items was an increase in gross margin related to an increase in customer growth, a decrease in operation and maintenance expense, higher other income and a decrease in income tax expense; and


•	a decrease in net income attributable to OGE Holdings of $12.6 million, or $0.06 per diluted share of the Company's common stock, primarily due to lower average natural gas prices and lower NGLs prices.

These decreases were partially offset by an increase in net income attributable to OGE Energy of $4.7 million, or $0.03 per diluted share of the Company's common stock, primarily due to gains associated with the deferred compensation plan.

2015 Outlook

The Company's estimate of 2015 consolidated earnings guidance of $1.76 to $1.89 per average diluted share and distributable cash flow from Enable between $139 million and $142 million are unchanged. See the Company's 2014 Form 10-K for other key factors and assumptions underlying its 2015 earnings guidance.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the three and six months ended June 30, 2015 as compared to the same period in 2014 and the Company's consolidated financial position at June 30, 2015. Due to seasonal fluctuations and other factors, the Company's operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 or for any future period. The following information should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.



	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions except per share data)	2015		2014		2015		2014
Net income attributable to OGE Energy	$	87.5	$	100.8	$	130.7	$	150.1
Basic average common shares outstanding	199.6		199.2		199.6		199.0
Diluted average common shares outstanding	199.6		200.0		199.6		199.8
Basic earnings per average common share	$	0.44	$	0.51	$	0.66	$	0.75
Diluted earnings per average common share	$	0.44	$	0.50	$	0.66	$	0.75
Dividends declared per common share	$	0.25000	$	0.22500	$	0.50000	$	0.45000

Results by Business Segment



	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2015		2014			2015		2014
Net income attributable to OGE Energy
OG&E (Electric Utility)	$	69.0	$	76.9		$	86.1	$	97.6
OGE Holdings (Natural Gas Midstream Operations)	18.0		24.0			40.8		53.4
Other Operations (A)	0.5		(0.1		)	3.8		(0.9		)
Consolidated net income attributable to OGE Energy	$	87.5	$	100.8		$	130.7	$	150.1


(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.

OG&E (Electric Utility)



	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Dollars in millions)	2015		2014		2015		2014
Operating revenues	$	549.9	$	611.8	$	1,030.0	$	1,172.2
Cost of sales	210.9		270.9		422.5		564.3
Other operation and maintenance	115.6		115.0		229.9		232.1
Depreciation and amortization	74.3		65.0		148.1		129.3
Taxes other than income	21.6		18.7		44.7		42.5
Operating income	127.5		142.2		184.8		204.0
Allowance for equity funds used during construction	1.7		0.8		3.2		1.9
Other income	3.3		0.9		5.0		0.6
Other expense	0.6		0.5		0.9		0.9
Interest expense	37.3		37.5		74.1		71.4
Income tax expense	25.6		29.0		31.9		36.6
Net income	$	69.0	$	76.9	$	86.1	$	97.6
Operating revenues by classification
Residential	$	214.0	$	217.2	$	408.6	$	437.7
Commercial	140.6		149.4		246.5		273.1
Industrial	49.3		56.0		91.0		106.8
Oilfield	42.1		47.5		79.1		91.8
Public authorities and street light	51.3		56.1		90.7		104.0
Sales for resale	9.0		11.4		20.8		28.0
System sales revenues	506.3		537.6		936.7		1,041.4
Off-system sales revenues	11.0		33.2		21.3		52.2
Other	32.6		41.0		72.0		78.6
Total operating revenues	$	549.9	$	611.8	$	1,030.0	$	1,172.2
Reconciliation of gross margin to revenue:
Operating revenues	$	549.9	$	611.8	$	1,030.0	$	1,172.2
Cost of sales	210.9		270.9		422.5		564.3
Gross Margin	$	339.0	$	340.9	$	607.5	$	607.9
Megawatt-hour sales by classification (In millions)
Residential	2.0		2.0		4.3		4.5
Commercial	2.0		1.9		3.6		3.5
Industrial	0.9		0.9		1.8		1.8
Oilfield	0.8		0.9		1.7		1.7
Public authorities and street light	0.8		0.9		1.5		1.6
Sales for resale	0.2		0.2		0.5		0.5
System sales	6.7		6.8		13.4		13.6
Off-system sales	0.5		0.8		0.7		1.2
Total sales	7.2		7.6		14.1		14.8
Number of customers	819,483		810,509		819,483		810,509
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	2.704		4.690		2.664		5.188
Coal	2.174		2.138		2.144		2.142
Total fuel	2.220		2.628		2.209		2.938
Total fuel and purchased power	2.891		3.437		2.896		3.613
Degree days (A)
Heating - Actual	143		205		1,984		2,270
Heating - Normal	203		203		2,001		2,001
Cooling - Actual	610		683		621		692
Cooling - Normal	625		625		638		638


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

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

Three Months Ended June 30, 2015 as Compared to Three Months Ended June 30, 2014

OG&E's net income decreased $7.9 million, or 10.3 percent, during the three months ended June 30, 2015 as compared to the same period in 2014 primarily due to higher depreciation and amortization expense, higher taxes other than income, lower gross margin and higher other operation and maintenance partially offset by higher other income and lower interest expense.

Gross Margin

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.

Operating revenues were $549.9 million during the three months ended June 30, 2015 as compared to $611.8 million during the same period in 2014, a decrease of $61.9 million, or 10.1 percent. Cost of sales were $210.9 million during the three months ended June 30, 2015 as compared to $270.9 million during the same period in 2014, a decrease of $60.0 million, or 22.1 percent. Gross margin was $339.0 million during the three months ended June 30, 2015 as compared to $340.9 million during the same period in 2014, a decrease of $1.9 million, or 0.6 percent. The below factors contributed to the change in gross margin:



	$ Change
	(In millions)
Wholesale transmission revenue (A)	$	(10.0	)
Quantity variance (primarily weather)	(4.8		)
Non-residential demand and related revenues	0.8
New customer growth	5.2
Price variance (B)	6.3
Other	0.6
Change in gross margin	$	(1.9	)


(A)	Decreased primarily due to a true up for the base plan projects in the SPP formula rate for 2014 and for the three months ended June 30, 2015 as well as 2013 and 2014 point-to-point credits shared with retail customers.


(B)	Increased primarily due to sales and customer mix.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $105.9 million during the three months ended June 30, 2015 as compared to $151.2 million during the same period in 2014, a decrease of $45.3 million, or 30.0 percent, primarily due to a decrease in natural gas prices and a decrease in generation. Purchased power costs were $94.1 million during the three months ended June 30, 2015 as compared to $110.9 million during the same period in 2014, a decrease of $16.8 million, or 15.1 percent, primarily due to decreases of $7.7 million in cogeneration purchases, $7.0 million in purchases from the Integrated Market, $2.8 million in wind purchased power, and $0.3 million in non-wind purchase power agreements, offset by an increase of $1.0 million in transmission and curtailment expenses. Transmission expense is charged to OG&E by the SPP for the utilization of transmission systems owned by other SPP members and is recovered from retail customers through the SPP Cost Tracker in Oklahoma and through the Transmission Cost Rider in Arkansas. Transmission expenses were $10.9 million during the three months ended June 30, 2015 as compared to $8.8 million during the same period in 2014, an increase of $2.1 million, or 23.9 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

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

Operating Expenses

Other operation and maintenance expense was $115.6 million during the three months ended June 30, 2015 as compared to $115.0 million during the same period in 2014, an increase of $0.6 million, or 0.5 percent. The below factors contributed to the change in other operation and maintenance expense:



	$ Change
	(In millions)
Salaries and Wages (A)	$	3.1
Employee Benefits (B)	1.2
Other marketing, sales, and commercial (C)	0.8
Maintenance at power plants	0.2
Other	0.6
Contract Professional Services	(0.7		)
Additional capitalized labor (D)	(1.9		)
Vegetation Management (E)	(2.7		)
Change in other operation and maintenance expense	$	0.6


(A)	Increased primarily due to annual salary increases and increased overtime.


(B)	Increased primarily due to higher actual medical costs incurred.


(C)	Increased primarily due to demand side management customer payments which are recovered through a rider.


(D)	Increased due to more capital projects.


(E)	Decreased due to less tree trimming related to increased rainfall in May 2015.

Depreciation and amortization expense was $74.3 million during the three months ended June 30, 2015 as compared to $65.0 million during the same period in 2014, an increase of $9.3 million, or 14.3 percent, primarily due to additional assets being placed in service, along with an increase resulting from the amortization of the deferred pension credits regulatory liability which was fully amortized in July 2014.

Additional Information

Other Income. Other income was $3.3 million during the three months ended June 30, 2015 as compared to a net gain of $0.9 million during the same period in 2014, an increase of $2.4 million, primarily due to increased guaranteed flat bill margins.

Income Tax Expense. Income tax expense was $25.6 million during the three months ended June 30, 2015 as compared to $29.0 million during the same period in 2014, a decrease of $3.4 million, or 11.7 percent, primarily due to lower pretax income partially offset by a reduction in tax credits.

Six Months Ended June 30, 2015 as Compared to Six Months Ended June 30, 2014

OG&E's net income decreased $11.5 million, or 11.8 percent, during the six months ended June 30, 2015 as compared to the same period in 2014 primarily due to higher depreciation and amortization expense, higher interest expense, higher taxes other than income and lower gross margin partially offset by higher other income, a decrease in income tax, and lower other operation and maintenance.

Gross Margin

Operating revenues were $1,030.0 million during the six months ended June 30, 2015 as compared to $1,172.2 million during the same period in 2014, a decrease of $142.2 million, or 12.1 percent. Cost of sales were $422.5 million during the six months ended June 30, 2015 as compared to $564.3 million during the same period in 2014, a decrease of $141.8 million, or 25.1 percent. Gross margin was $607.5 million during the six months ended June 30, 2015 as compared to $607.9 million during the same period in 2014, a decrease of $0.4 million, or 0.1 percent. The below factors contributed to the change in gross margin:



	$ Change
	(In millions)
Quantity variance (primarily weather)	$	(15.4	)
Wholesale transmission revenue (A)	(9.2		)
Non-residential demand and related revenues	1.2
New customer growth	9.6
Price variance (B)	12.2
Other	1.2
Change in gross margin	$	(0.4	)


(A)	Decreased primarily due to a true up for the base plan projects in the SPP formula rate for 2014 and for the six months ended June 30, 2015 as well as 2013 and 2014 point-to-point credits shared with retail customers.


(B)	Increased primarily due to sales and customer mix.

Cost of sales for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $219.7 million during the six months ended June 30, 2015 as compared to $346.3 million during the same period in 2014, a decrease of $126.6 million, or 36.6 percent, primarily due to a decrease in natural gas prices and decreased generation. Purchased power costs were $180.6 million during the six months ended June 30, 2015 as compared to $200.8 million during the same period in 2014, a decrease of $20.2 million, or 10.1 percent, primarily due to decreases of $9.5 million in cogeneration purchases, $6.0 million in wind purchased power, $4.1 million in purchases from the Integrated Market, $1.1 million in Spot Market purchases, and $0.3 million in non-wind purchase power agreements, offset by an increase of $0.8 million in transmission and curtailment expenses. Transmission expense is charged to OG&E by the SPP for the utilization of transmission systems owned by other SPP members and is recovered from retail customers through the SPP Cost Tracker in Oklahoma and through the Transmission Cost Rider in Arkansas. Transmission expenses were $22.2 million during the six months ended June 30, 2015 as compared to $17.2 million during the same period in 2014, an increase of $5.0 million, or 29.1 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

Operating Expenses

Other operation and maintenance expense was $229.9 million during the six months ended June 30, 2015 as compared to $232.1 million during the same period in 2014, a decrease of $2.2 million, or 0.9 percent. The below factors contributed to the change in other operation and maintenance expense:



	$ Change
	(In millions)
Additional capitalized labor (A)	$	(3.9	)
Maintenance at power plants (B)	(3.7		)
Vegetation Management (C)	(2.8		)
Contract Professional Services	(1.2		)
Other marketing, sales and commercial (D)	1.8
Employee Benefits (E)	2.5
Salaries and Wages (F)	4.6
Other	0.5
Change in other operation and maintenance expense	$	(2.2	)


(A)	Increased due to more capital projects.


(B)	Decreased primarily due to less work at the power plant.


(C)	Decreased due to less tree trimming related to increased rainfall in May 2015.


(D)	Increased primarily due to demand side management customer payments which are recovered through a rider.


(E)	Increased primarily due to higher actual medical costs incurred.


(F)	Increased primarily due to annual salary increases.

Depreciation and amortization expense was $148.1 million during the six months ended June 30, 2015 as compared to $129.3 million during the same period in 2014, an increase of $18.8 million, or 14.5 percent, primarily due to additional assets being placed in service, along with an increase resulting from the amortization of the deferred pension credits and post-retirement medical regulatory liabilities which was fully amortized in July 2014 and the amortization of deferred storm costs that began April 2014.

Additional Information

Allowance for Equity Funds Used During Construction. Allowance for Equity Funds Used During Construction was $3.2 million during the six months ended June 30, 2015 as compared to $1.9 million during the same period in 2014, an increase of $1.3 million, or 68.4 percent, primarily due to higher construction work in progress balances resulting from increased spending for environmental projects.

Other Income. Other income was $5.0 million during the six months ended June 30, 2015 as compared to $0.6 million during the same period in 2014, an increase of $4.4 million, primarily due to increased guaranteed flat bill margins.

Interest Expense. Interest expense was $74.1 million during the six months ended June 30, 2015 as compared to $71.4 million during the same period in 2014, an increase of $2.7 million, or 3.8 percent, primarily due to an increase in interest on long term debt related to a $250 million debt issuance that occurred in March 2014 and a $250 million debt issuance that occurred in December 2014.

Income Tax Expense. Income tax expense was $31.9 million during the six months ended June 30, 2015 as compared to $36.6 million during the same period in 2014, a decrease of $4.7 million, or 12.8 percent, primarily due to lower pretax income and partially offset by a reduction in tax credits.

OGE Holdings (Natural Gas Midstream Operations)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2015			2014			2015			2014
Operating revenues	$	—		$	—		$	—		$	—
Cost of sales	—			—			—			—
Other operation and maintenance	0.2			0.4			1.0			0.4
Depreciation and amortization	—			—			—			—
Taxes other than income	—			—			—			—
Operating income	(0.2		)	(0.4		)	(1.0		)	(0.4		)
Equity in earnings of unconsolidated affiliates	28.2			39.3			59.9			87.2
Other income	—			—			—			—
Other expense	—			—			—			—
Interest expense	—			—			—			—
Income before taxes	28.0			38.9			58.9			86.8
Income tax expense	10.0			14.9			18.1			33.4
Net income attributable to OGE Holdings	$	18.0		$	24.0		$	40.8		$	53.4

Three Months Ended June 30, 2015 as Compared to Three Months Ended June 30, 2014

OGE Holding's net income for the three months ended June 30, 2015 as compared to the same period in 2014 decreased $6.0 million, or 25.0 percent, primarily due to an $11.1 million decrease in equity in earnings of Enable. The decrease in equity in earnings of Enable reflected an $11.6 million decrease in the Company's share of Enable's net income. Enable's gathering and processing business segment reported a decrease in operating income primarily from a decrease in gross margin, an increase in operation and maintenance expense, an increase in depreciation and amortization expense and an increase in taxes other than income taxes. Gathering and processing gross margin decreased primarily due to lower average natural gas prices and lower processing margin due to lower NGLs prices. Enable's transportation and storage business segment reported a decrease in operating income primarily from a decrease in unrealized gains on natural gas derivatives, a decrease in liquid sales due to lower NGLs prices, a decrease in storage demand fees, and a decrease in transportation services partially offset by higher system optimization opportunities and an increase in off-system transportation sales.

Income Tax Expense. Income tax expense was $10.0 million during the three months ended June 30, 2015 as compared to $14.9 million during the same period in 2014, a decrease of $4.9 million primarily reflecting lower pretax income.

Six Months Ended June 30, 2015 as Compared to Six Months Ended June 30, 2014

OGE Holding's net income for the six months ended June 30, 2015 as compared to the same period in 2014 decreased $12.6 million, or 23.6 percent, primarily due to a $27.3 million decrease in equity in earnings of Enable. The decrease in equity in earnings of Enable reflected a $30.3 million decrease in the Company's share of Enable's net income. Enable's gathering and processing business segment reported a decrease in operating income primarily from a decrease in gross margin, an increase in operation and maintenance expense, an increase in depreciation and amortization expense and an increase in taxes other than income taxes. Gathering and processing gross margin decreased primarily due to lower average natural gas prices, lower processing margin due to lower NGLs prices. Enable's transportation and storage business segment reported a decrease in operating income primarily from a decrease in unrealized gains on natural gas derivatives, a decrease in liquid sales due to lower NGLs prices and a decrease in storage demand fees and a decrease in transportation services partially offset by higher system optimization opportunities and an increase in off-system transportation sales.

Income Tax Expense. Income tax expense was $18.1 million during the six months ended June 30, 2015 as compared to $33.4 million during the same period in 2014, a decrease of $15.3 million primarily reflecting lower pretax income and a benefit recognized associated with a remeasurement of deferred taxes related to the Company's investment in Enable.

Reconciliation of Equity in Earnings of Unconsolidated Affiliates

The following table reconciles the Company's equity in earnings of its unconsolidated affiliates for the three and six months ended June 30, 2015 as compared to the same period in 2014:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
	(In millions)
OGE's share of Enable Net Income	$	20.6	$	32.2	$	44.4	$	74.7
Amortization of basis difference	3.6		3.4		7.1		7.0
Elimination of Enogex Holdings fair value and other adjustments	4.0		3.7		8.4		5.5
OGE's Equity in earnings of unconsolidated affiliates	$	28.2	$	39.3	$	59.9	$	87.2

Enable Results of Operations

The following table represents summarized financial information of Enable for the three and six months ended June 30, 2015 as compared to the same period in 2014:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
	(In millions)
Operating revenues	$	590	$	827	$	1,206	$	1,828
Cost of sales	277		478		569		1,111
Operating income	93		139		197		301
Net income	77		120		168		269

Enable Operating Data

The following table presents Enable's operating data for the three and six months ended June 30, 2015 as compared to the same period in 2014:



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2015	2014	2015	2014

Gathered volumes - TBtu/d	3.19	3.41	3.19	3.35
Transportation volumes - TBtu/d	4.97	4.97	5.34	5.26
Natural gas processed volumes - TBtu/d	1.84	1.55	1.76	1.50
NGLs sold - million gallons/d (A)(B)	75.91	73.75	71.68	69.98


(A)	Excludes volumes billed under throughput agreements.


(B)	Excludes condensate. Includes third party processing.

Off-Balance Sheet Arrangement

There have been no significant changes in the Company's off-balance sheet arrangement from that discussed in the Company's 2014 Form 10-K. The Company has no off-balance sheet arrangements with equity method investments that would affect its liquidity.

Liquidity and Capital Resources

Working Capital

Working capital is defined as the amount by which current assets exceed 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.

The balance of Accounts Receivable and Accrued Unbilled Revenues was $274.6 million and $249.9 million at June 30, 2015 and December 31, 2014, respectively, an increase of $24.7 million, or 9.9 percent, primarily due to an increase in billings to OG&E's retail customers reflecting higher usage due to warmer weather in June 2015 as compared to December 2014.

The balance of Fuel Inventories was $89.4 million and $58.5 million at June 30, 2015 and December 31, 2014, respectively, an increase of $30.9 million, or 52.8 percent, primarily due to higher coal inventory balances at OG&E's coal fired plants resulting from increased deliveries and higher average prices in the six months ended June 2015 as compared to December 2014.

The balance of Deferred Income Taxes was $173.1 million and $191.4 million at June 30, 2015 and December 31, 2014, respectively, a decrease of $18.3 million, or 9.6 percent, primarily due to current year accruals and an adjustment related to the 2014 tax earnings return to provision.

The balance of Fuel Clause Under Recoveries was $3.7 million and $68.3 million at June 30, 2015 and December 31, 2014, respectively, a decrease of $64.6 million, or 94.6 percent, primarily due to higher amounts billed to OG&E retail customers as compared to the actual cost of fuel and purchased power, partially offset by the movement of the Oklahoma jurisdiction to an over-recovery position of $1.6 million at the close of the second quarter. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result, OG&E under recovers fuel costs when the actual fuel and purchased power cost recoveries exceed fuel adjustment clause recoveries and over recovers fuel costs when the actual fuel and purchased power costs are below the fuel adjustment clause recoveries. Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances into future cost recoveries.

The balance of Accounts Payable was $145.8 million and $179.1 million at June 30, 2015 and December 31, 2014, respectively, a decrease of $33.3 million, or 18.6 percent, primarily due to the timing of vendor payments and a decrease in accruals.

The balance of Long-term Debt Due Within One Year was $110.0 million as of June 30, 2015 compared to no balance at December 31, 2014 primarily due to the reclassification of long-term debt that will mature in January 2016.

Cash Flows



	Six Months Ended
	June 30,						2015 vs. 2014
(In millions)	2015			2014			$ Change			% Change
Net cash provided from operating activities	$	305.8		$	181.8		$	124.0		68.2	%
Net cash used in investing activities	(225.7		)	(297.0		)	71.3			24.0	%
Net cash provided from (used in) financing activities	(85.6		)	110.6			(196.2		)	*

* Change is greater than 100%.

Operating Activities

The increase of $124.0 million, or 68.2 percent, in net cash provided from operating activities during the six months ended June 30, 2015 as compared to the same period in 2014 was primarily due to an increase in cash received from fuel under recoveries.

Investing Activities

The decrease of $71.3 million, or 24.0 percent, in net cash used in investing activities during the six months ended June 30, 2015 as compared to the same period in 2014 was primarily due to a decrease in transmission projects at OG&E.

Financing Activities

The increase of $196.2 million in net cash used in financing activities during the six months ended June 30, 2015 as compared to the same period in 2014 was primarily due to the issuance of $250 million in long-term debt during the first quarter of 2014 partially offset by an increase 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 2015 through 2019 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)	2015		2016		2017		2018		2019
OG&E Base Transmission	$	40	$	30	$	30	$	30	$	30
OG&E Base Distribution	180		175		175		175		175
OG&E Base Generation	90		75		75		75		75
OG&E Other	55		25		25		25		25
Total Base Transmission, Distribution, Generation and Other	365		305		305		305		305
OG&E Known and Committed Projects:
Transmission Projects:
Other Regionally Allocated Projects (A)	15		20		20		20		20
Large SPP Integrated Transmission Projects (B) (C)	30		35		25		10		60
Total Transmission Projects	45		55		45		30		80
Other Projects:
Smart Grid Program	10		10		—		—		—
Environmental - low NOX burners (D)	25		20		10		—		—
Environmental - activated carbon injection (D)	20		—		—		—		—
Environmental - natural gas conversion (D)	—		—		—		40		35
Environmental - scrubbers (D)	80		150		140		95		20
Combustion turbines - Mustang Modernization	55		180		100		50		5
Total Other Projects	190		360		250		185		60
Total Known and Committed Projects	235		415		295		215		140
Total	$	600	$	720	$	600	$	520	$	445


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


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



(C)	Project Type	Project Description	Estimated Cost (In millions)	Projected In-Service Date
	Integrated Transmission Project	30 miles of transmission line from OG&E's Gracemont substation to an AEP companion transmission line to its Elk City substation	$45	Early 2018
	Integrated Transmission Project	126 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to OG&E's Cimarron substation; construction of the Mathewson substation on this transmission line	$180	Early 2021

(D)

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

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

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 ratings 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 by itself would not result in any defaults or accelerations. Any future downgrade could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash 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, distributions from equity method investments and proceeds from the sales of common stock to the public through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan or other 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 Credit Facilities

Short-term borrowings generally are used to meet working capital requirements. The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements. At June 30, 2015, the Company has revolving credit facilities totaling in the aggregate $1,150.0 million. These bank facilities can also be used as letter of credit facilities. The short-term debt balance was $105.5 million and $98.0 million at June 30, 2015 and December 31, 2014, respectively. The weighted-average interest rate on short-term debt at June 30, 2015 was 0.48 percent. The average balance of short-term debt during the six months ended June 30, 2015 was $128.0 million at a weighted-average interest rate of 0.47 percent. The maximum month-end balance of short-term debt during the six months ended June 30, 2015 was $180.0 million. At June 30, 2015, there were $1.9 million supporting letters of credit at a weighted-average interest rate of 0.95 percent. At June 30, 2015, the Company had $1,042.6 million of net available liquidity under its revolving credit agreements. OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2015 and ending December 31, 2016. At June 30, 2015, the Company had no cash and cash equivalents. See Note 9 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

Quarterly Distributions by Enable

Pursuant to the Enable Agreement, during the second quarter of 2015 Enable made distributions of approximately $34.6 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, but conservative, 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, impairment estimates of long-lived assets (including intangible assets), and income taxes. For the electric utility segment, significant judgment is also exercised in contingency reserves, asset retirement obligations, the allowance for uncollectible accounts and the valuation 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 2014 Form 10-K.

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 2014 Form 10-K. Except as set forth below, there have been no material changes to such items.

OG&E expects that environmental expenditures necessary to comply with the environmental laws and regulations discussed below will qualify as part of a pre-approval plan to handle state and Federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E's retail customers under House Bill 1910, which was enacted into law in May 2005.

Air

Regional Haze Control Measures

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

On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the regional haze rule. The SIP was subject to the EPA's review and approval.

The Oklahoma SIP included requirements for reducing emissions of NO_Xand SO₂ from OG&E's seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations. The SIP also included a waiver from BART requirements for all eligible units at the Horseshoe Lake generating station based on air modeling that showed no significant impact on visibility in nearby national parks and wilderness areas. The SIP concluded that BART for reducing NO_X emissions at all of the subject units should be the installation of low NO_X burners with overfire air (flue gas recirculation was also required on two of the units) and set forth associated NO_X emission rates and limits.

On December 28, 2011, the EPA issued a final rule in which it rejected the SO₂ portion of the Oklahoma SIP and issued a FIP in its place. OG&E and the State of Oklahoma's subsequent appeal of the FIP with the Tenth Circuit of Appeals and the U.S.

Supreme Court ended on May 27, 2014 when the Supreme Court denied Petition for Certiorari, upholding the EPA's FIP for SO₂. The FIP compliance date is now January 4, 2019.

Federal Clean Air Act New Source Review Litigation

As previously reported, in July 2008, OG&E received a request for information from the EPA regarding Federal Clean Air Act compliance at OG&E's Muskogee and Sooner generating plants.

proceedings, the Sierra Club could seek to require OG&E to install additional pollution control equipment at Muskogee 6, including scrubbers, baghouses and selective catalytic reduction systems and pay fines and significant penalties as a result of the allegations. Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation. Due to the uncertain and preliminary nature of this litigation, OG&E cannot provide a range of reasonably possible loss in this case.

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 the end of 2014, no areas of Oklahoma had been designated as non-attainment for pollutants that are likely to affect the Company's operations. On March 2, 2015, the U.S. District Court for the Northern District of California issued an order granting the EPA and the Sierra Club's joint motion to approve and enter a consent decree that requires the EPA to promulgate and publish the remaining area designations. Non-attainment area designations are due to the EPA by September 18, 2015 and are subject to the EPA's approval. 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.

Hazardous Air Pollutants Emission Standards

On April 16, 2012, regulations governing emissions of certain hazardous air pollutants from electric generating units were published as the final MATS rule. This rule includes numerical standards for particulate matter (as a surrogate for toxic metals), hydrogen chloride and mercury emissions from coal-fired boilers. Compliance is required within three years after the effective date of the rule with the possibility of a one-year extension. OG&E requested and received a one-year extension for complying or until April 16, 2016. To comply with this rule, OG&E is currently planning to utilize activated carbon injection at each of its five coal-fired units.

The final MATS rule was appealed by several parties, but OG&E was not a party to the appeals. After withstanding judicial scrutiny at the District of Columbia Circuit Court of Appeals, the MATS rule was challenged at the U.S. Supreme Court. On June 29, 2015, the U.S. Supreme Court found that the EPA should have considered the compliance costs imposed on utilities at the first stage of the Agency’s regulatory analysis. The U.S. Supreme Court did not vacate the rule, but reversed the D.C. Circuit and remanded to the D.C. Circuit for further proceedings. The MATS rule currently remains in effect and OG&E is still required to meet the April 2016 compliance deadline unless the D.C. Circuit vacates the rule or grants some other relief from the compliance mandate.

Clean Power Plan

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 2014 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).

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Item 3 of Part I of the Company's 2014 Form 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 2014 Form 10-K, which are incorporated herein by reference.

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

The following table contains information about the Company's purchases of its common stock during the second quarter of 2015.



Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
04/01/15 - 04/30/15	91	(A)	$	32.39	N/A	N/A
05/01/15 - 05/31/15	—		$	—	N/A	N/A
06/01/15 - 06/30/15	—		$	—	N/A	N/A


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

Item 6. Exhibits.



Exhibit No.	Description
3.01	OGE Energy Corp. Amended By-laws effective as of May 29, 2015. (Filed as Exhibit 3.01 to the Company's Form 8-K filed June 1, 2015 (File No. 1-12579) and incorporated by reference herein)
3.02	OG&E Amended By-laws effective as of May 29, 2015. (Filed as Exhibit 3.02 to the Company's Form 8-K filed June 1, 2015 (File No. 1-12579) and incorporated by reference herein)
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.03	Copy of the Report of the Administrative Law Judge dated June 8, 2015. (Filed as Exhibit 99.02 to the Company's Form 8-K filed June 12, 2015 (File No. 1-12579) and incorporated by reference herein)
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.PRE	XBRL Taxonomy Presentation Linkbase Document.
101.LAB	XBRL Taxonomy Label Linkbase Document.
101.CAL	XBRL Taxonomy Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

SIGNATURE

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



	OGE ENERGY CORP.
	(Registrant)

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

August 6, 2015