OGE ENERGY CORP. - Quarter Report: 2013 September (Form 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 September 30, 2013

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 September 30, 2013, there were 198,453,261 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS



	Page
GLOSSARY OF TERMS	2
FORWARD-LOOKING STATEMENTS	1

Part I - FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	4
Condensed Consolidated Statements of Cash Flows	5
Condensed Consolidated Balance Sheets	6
Condensed Consolidated Statements of Changes in Stockholders' Equity	8
Notes to Condensed Consolidated Financial Statements	9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3. Quantitative and Qualitative Disclosures About Market Risk	52

Item 4. Controls and Procedures	52

Part II - OTHER INFORMATION
Item 1. Legal Proceedings	52

Item 1A. Risk Factors	52

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53

Item 5. Other Information	53

Item 6. Exhibits	54

Signature	55

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 2012 Form 10-K and "Item 1A. Risk Factors" 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 Midstream Partners serves, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable Midstream Partners' interstate pipelines;


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


•	business conditions in the energy and natural gas midstream industries;


•	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 Midstream Partners that the Company does not control;


•	the risk that Enable Midstream Partners may not be able to successfully integrate the operations of Enogex LLC and the businesses contributed by CenterPoint as discussed in Note 3; 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 2012 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.

GLOSSARY OF TERMS

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



Abbreviation	Definition
2012 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2012
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ASC	Financial Accounting Standards Board Accounting Standards Codification
BART	Best available retrofit technology
CenterPoint	CenterPoint Energy Resources Corp., wholly-owned subsidiary of CenterPoint Energy, Inc.
Company	OGE Energy, collectively with its subsidiaries
DOJ	U.S. Department of Justice
Dry Scrubbers	Dry flue gas desulfurization units with spray dryer absorber
Enable Midstream Partners	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
MRT	CenterPoint Energy - Mississippi River Transmission, LLC, a Delaware limited liability company
NGLs	Natural gas liquids
NOX	Nitrogen oxide
NYMEX	New York Mercantile Exchange
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 28.5 percent owner of Enable Midstream Partners
Pension Plan	Qualified defined benefit retirement plan
PRM	Price risk management
PSO	Public Service Company of Oklahoma
PUD Staff	Public Utility Division Staff of the Oklahoma Corporation Commission
Restoration of Retirement Income Plan	Supplemental retirement plan to the Pension Plan
SIP	State implementation plan
SO₂	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
TBtu/d	Trillion British thermal units per day

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions except per share data)	2013			2012			2013			2012
OPERATING REVENUES
Electric Utility operating revenues	$	723.2		$	721.0		$	1,753.3		$	1,675.7
Natural Gas Midstream Operations operating revenues (Note 1)	—			392.4			605.5			1,133.4
Total operating revenues	723.2			1,113.4			2,358.8			2,809.1
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	273.0			259.8			715.2			636.1
Natural Gas Midstream Operations cost of goods sold (Note 1)	—			279.8			481.4			798.1
Total cost of goods sold	273.0			539.6			1,196.6			1,434.2
Gross margin on revenues	450.2			573.8			1,162.2			1,374.9
OPERATING EXPENSES
Other operation and maintenance	102.2			147.1			372.2			447.7
Depreciation and amortization	65.4			93.0			231.7			270.1
Impairment of assets	—			—			—			0.3
Gain on insurance proceeds	—			—			—			(7.5		)
Taxes other than income	21.7			29.7			78.1			84.7
Total operating expenses	189.3			269.8			682.0			795.3
OPERATING INCOME	260.9			304.0			480.2			579.6
OTHER INCOME (EXPENSE)
Equity in earnings of unconsolidated affiliates (Note 1)	46.0			—			64.5			—
Allowance for equity funds used during construction	1.7			1.3			4.4			4.9
Other income	6.2			2.6			25.4			12.8
Other expense	(5.2		)	(5.6		)	(15.9		)	(11.1		)
Net other income (expense)	48.7			(1.7		)	78.4			6.6
INTEREST EXPENSE
Interest on long-term debt	35.0			40.2			110.7			118.3
Allowance for borrowed funds used during construction	(0.9		)	(0.8		)	(2.3		)	(2.8		)
Interest on short-term debt and other interest charges	(0.4		)	2.2			3.8			6.6
Interest expense	33.7			41.6			112.2			122.1
INCOME BEFORE TAXES	275.9			260.7			446.4			464.1
INCOME TAX EXPENSE	60.7			68.3			110.2			122.6
NET INCOME	215.2			192.4			336.2			341.5
Less: Net income attributable to noncontrolling interests	—			6.9			6.2			25.0
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	215.2		$	185.5		$	330.0		$	316.5
BASIC AVERAGE COMMON SHARES OUTSTANDING	198.4			197.4			198.1			197.0
DILUTED AVERAGE COMMON SHARES OUTSTANDING	199.7			198.3			199.3			197.9
BASIC EARNINGS PER AVERAGE COMMON SHARE ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	1.08		$	0.94		$	1.67		$	1.61
DILUTED EARNINGS PER AVERAGE COMMON SHARES ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	1.08		$	0.94		$	1.66		$	1.60
DIVIDENDS DECLARED PER COMMON SHARE	$	0.20875		$	0.19625		$	0.62625		$	0.58875

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						Nine Months Ended
	September 30,						September 30,
(In millions)	2013			2012			2013			2012
Net income	$	215.2		$	192.4		$	336.2		$	341.5
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, $0.4, $1.8 and $1.3, respectively	0.9			0.8			2.8			2.3
Amortization of prior service cost, net of tax of $0, $0, $0 and $0.1, respectively	—			—			—			0.1
Postretirement Benefit Plans:
Amortization of deferred net loss, net of tax of $0.3, $0.2, $0.9 and $0.8, respectively	0.6			0.5			1.6			1.5
Amortization of deferred net transition obligation, net of tax of $0, $0.1, $0 and $0.1, respectively	—			0.1			—			0.1
Amortization of prior service cost, net of tax of $(0.3), ($0.3), $(0.8) and ($0.8), respectively	(0.5		)	(0.5		)	(1.4		)	(1.4		)
Deferred commodity contracts hedging gains reclassified in net income, net of tax of $0.3, $0, $0.2 and ($1.6), respectively	0.3			—			0.2			(3.6		)
Deferred commodity contracts hedging losses, net of tax of $0, ($0.3), $0 and ($0.5), respectively	—			(0.5		)	—			(0.5		)
Amortization of deferred interest rate swap hedging losses, net of tax of $0, $0, $0.1 and $0.1, respectively	0.1			0.1			0.2			0.2
Other comprehensive income (loss), net of tax	1.4			0.5			3.4			(1.3		)
Comprehensive income (loss)	216.6			192.9			339.6			340.2
Less: Comprehensive income attributable to noncontrolling interests	—			6.9			6.3			24.1
Less: Deconsolidation of Enogex Holdings	—			—			6.1			—
Total comprehensive income attributable to OGE Energy	$	216.6		$	186.0		$	327.2		$	316.1

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended
	September 30,
(In millions)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	336.2		$	341.5
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	233.0			273.0
Impairment of assets	—			0.3
Deferred income taxes and investment tax credits, net	106.5			130.9
Equity in earnings of unconsolidated affiliates	(64.5		)	—
Allowance for equity funds used during construction	(4.4		)	(4.9		)
(Gain) loss on disposition and abandonment of assets	(8.7		)	1.8
Gain on insurance proceeds	—			(7.5		)
Stock-based compensation	(4.9		)	(7.1		)
Distributions from unconsolidated affiliates	17.4			—
Regulatory assets	7.4			17.5
Regulatory liabilities	(16.9		)	(12.8		)
Other assets	(9.2		)	(3.1		)
Other liabilities	(18.5		)	(22.4		)
Change in certain current assets and liabilities
Accounts receivable, net	(111.8		)	(68.2		)
Accrued unbilled revenues	(13.3		)	(3.2		)
Income taxes receivable	1.6			1.0
Fuel, materials and supplies inventories	5.2			13.7
Fuel clause under recoveries	—			1.0
Other current assets	(0.2		)	(11.7		)
Accounts payable	(15.3		)	(81.5		)
Accounts payable - unconsolidated affiliates	4.9			—
Fuel clause over recoveries	(97.2		)	99.4
Other current liabilities	3.9			20.3
Net Cash Provided from Operating Activities	351.2			678.0
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(772.9		)	(792.8		)
Investment in unconsolidated affiliates	(2.7		)	—
Acquisition of gathering assets	—			(80.5		)
Proceeds from insurance	—			7.6
Reimbursement of capital expenditures	—			28.2
Proceeds from sale of assets	36.2			0.9
Net Cash Used in Investing Activities	(739.4		)	(836.6		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	247.4			250.0
Changes in advances with unconsolidated affiliates	131.8			—
Contributions from noncontrolling interest partners	107.0			1.0
Increase in short-term debt	16.1			178.5
Issuance of common stock	10.8			10.9
Repayment of line of credit	—			(150.0		)
Payment of long-term debt	(0.2		)	—
Distributions to noncontrolling interest partners	(2.5		)	(10.3		)
Dividends paid on common stock	(124.0		)	(115.9		)
Net Cash Provided from Financing Activities	386.4			164.2
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1.8		)	5.6
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1.8			4.6
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	10.2

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS



(In millions)	September 30, 2013 (Unaudited)		December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	—	$	1.8
Accounts receivable, less reserve of $2.0 and $2.6, respectively	257.2		295.3
Accounts receivable - unconsolidated affiliates	9.0		—
Accrued unbilled revenues	70.7		57.4
Income taxes receivable	5.6		7.2
Fuel inventories	75.5		93.3
Materials and supplies, at average cost	79.5		80.9
Deferred income taxes	230.2		187.7
Assets held for sale	—		25.5
Other	30.3		45.1
Total current assets	758.0		794.2
OTHER PROPERTY AND INVESTMENTS
Investment in unconsolidated affiliates	1,295.8		—
Other	56.2		52.2
Total other property and investments	1,352.0		52.2
PROPERTY, PLANT AND EQUIPMENT
In service	8,929.5		11,504.4
Construction work in progress	501.1		387.5
Total property, plant and equipment	9,430.6		11,891.9
Less accumulated depreciation	2,935.0		3,547.1
Net property, plant and equipment	6,495.6		8,344.8
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	496.2		510.6
Intangible assets, net	—		127.4
Goodwill	—		39.4
Other	42.4		53.6
Total deferred charges and other assets	538.6		731.0
TOTAL ASSETS	$	9,144.2	$	9,922.2

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

OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)



(In millions)	September 30, 2013 (Unaudited)			December 31, 2012
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	447.0		$	430.9
Accounts payable	171.1			396.7
Dividends payable	41.4			41.2
Customer deposits	69.5			70.3
Accrued taxes	57.2			48.1
Accrued interest	33.6			55.0
Accrued compensation	53.3			55.2
Fuel clause over recoveries	12.0			109.2
Other	56.4			69.8
Total current liabilities	941.5			1,276.4
LONG-TERM DEBT	2,400.0			2,848.6
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	367.7			399.8
Deferred income taxes	2,105.3			1,948.8
Deferred investment tax credits	2.4			3.9
Regulatory liabilities	242.7			245.1
Deferred revenues	0.3			37.7
Other	89.7			89.5
Total deferred credits and other liabilities	2,808.1			2,724.8
Total liabilities	6,149.6			6,849.8
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY
Common stockholders' equity	1,067.8			1,047.4
Retained earnings	1,978.7			1,772.4
Accumulated other comprehensive loss, net of tax	(51.9		)	(49.1		)
Treasury stock, at cost	—			(3.5		)
Total OGE Energy stockholders' equity	2,994.6			2,767.2
Noncontrolling interests	—			305.2
Total stockholders' equity	2,994.6			3,072.4
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	9,144.2		$	9,922.2

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)			Noncontrolling Interest			Treasury Stock			Total
Balance at December 31, 2012	$	1.0	$	1,046.4		$	1,772.4		$	(49.1	)	$	305.2		$	(3.5	)	$	3,072.4
Net income	—		—			330.0			—			6.2			—			336.2
Other comprehensive income (loss), net of tax	—		—			—			3.3			0.1			—			3.4
Dividends declared on common stock	—		—			(124.2		)	—			—			—			(124.2		)
Issuance of common stock	—		10.8			—			—			—			—			10.8
Stock-based compensation and other	—		(4.2		)	—			—			(0.8		)	3.5			(1.5		)
Contributions from noncontrolling interest partners	—		22.5			—			—			84.5			—			107.0
Distributions to noncontrolling interest partners	—		—			—			—			(2.5		)	—			(2.5		)
Deconsolidation of Enogex Holdings	—		—			0.5			(6.1		)	(392.7		)	—			(398.3		)
Deferred income taxes attributable to contributions from noncontrolling interest partners	—		(8.7		)	—			—			—			—			(8.7		)
2-for-1 forward stock split	1.0		(1.0		)	—			—			—			—			—
Balance at September 30, 2013	$	2.0	$	1,065.8		$	1,978.7		$	(51.9	)	$	—		$	—		$	2,994.6

Balance at December 31, 2011	$	1.0	$	1,034.3		$	1,574.8		$	(40.6	)	$	256.0		$	(6.2	)	$	2,819.3
Net income	—		—			316.5			—			25.0			—			341.5
Other comprehensive income (loss), net of tax	—		—			—			(0.4		)	(0.9		)	—			(1.3		)
Dividends declared on common stock	—		—			(116.2		)	—			—			—			(116.2		)
Issuance of common stock	—		10.9			—			—			—			—			10.9
Stock-based compensation and other	—		(11.6		)	—			—			(2.9		)	6.1			(8.4		)
Contributions from noncontrolling interest partners	—		—			—			—			1.0			—			1.0
Distributions to noncontrolling interest partners	—		—			—			—			(10.3		)	—			(10.3		)
Balance at September 30, 2012	$	1.0	$	1,033.6		$	1,775.1		$	(41.0	)	$	267.9		$	(0.1	)	$	3,036.5

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. For a discussion of the change in the Company’s business segments due to the formation of Enable Midstream Partners, see Note 12. For periods prior to May 1, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements. All significant intercompany transactions have been eliminated in consolidation.

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

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. 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.

As discussed below, the Company completed a 2-for-1 stock split of the Company's common stock effective July 1, 2013. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

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 September 30, 2013 and December 31, 2012, the results of its operations for the three and nine months ended September 30, 2013 and 2012 and the results of its cash flows for the nine months ended September 30, 2013 and 2012, 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 nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013 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 2012 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 refund in future rates.

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



(In millions)	September 30, 2013		December 31, 2012
Regulatory Assets
Current
Oklahoma demand program rider under recovery (A)	$	9.5	$	9.2
Crossroads wind farm rider under recovery (A)	7.2		14.9
Other (A)	6.8		2.9
Total Current Regulatory Assets	$	23.5	$	27.0
Non-Current
Benefit obligations regulatory asset	$	350.1	$	370.6
Income taxes recoverable from customers, net	55.7		54.7
Smart Grid	43.4		42.8
Deferred storm expenses	18.3		12.7
Unamortized loss on reacquired debt	12.1		13.0
Deferred pension expenses	1.9		4.5
Other	14.7		12.3
Total Non-Current Regulatory Assets	$	496.2	$	510.6
Regulatory Liabilities
Current
Fuel clause over recoveries	$	12.0	$	109.2
Smart Grid rider over recovery (B)	19.1		24.1
Other (B)	2.6		7.8
Total Current Regulatory Liabilities	$	33.7	$	141.1
Non-Current
Accrued removal obligations, net	$	219.2	$	218.2
Pension tracker	14.2		9.2
Deferred pension credits	9.3		17.7
Total Non-Current Regulatory Liabilities	$	242.7	$	245.1


(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.

Use of Estimates

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), income taxes, contingency reserves, asset retirement obligations and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas midstream operations segment, the most significant judgment is also exercised in the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill and equity method investments.

Investment in Unconsolidated Affiliate

OGE Energy's investment in Enable Midstream Partners 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 Midstream Partners since it does not have the power to direct the activities of Enable Midstream Partners that are considered most significant to the economic performance of Enable Midstream Partners. As discussed above, OGE Energy accounts for the investment in Enable Midstream Partners 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 Midstream Partners is limited to OGE Energy's equity investment in Enable Midstream Partners as presented on the Company's Condensed Consolidated Balance Sheet at September 30, 2013. The Company evaluates its equity method investments for impairment when events or changes in circumstances indicate there is a loss in value of the investment that is other than a temporary decline.

The Company considers distributions received from its unconsolidated affiliates 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 its unconsolidated affiliates 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 nine months ended September 30, 2013 and 2012.



	Nine Months Ended
	September 30,
(In millions)	2013			2012
Balance at January 1	$	54.0		$	24.8
Liabilities settled (A)	(0.4		)	0.3
Accretion expense	1.7			1.6
Revisions in estimated cash flows (B)	(0.7		)	26.7
Balance at September 30	$	54.6		$	53.4


(A)	As a result of the formation of Enable Midstream Partners on May 1, 2013, the Company has no obligations at September 30, 2013 under OGE Holdings' asset retirement obligations previously disclosed in the Company's 2012 10-K.


(B)	Due to changes to OG&E's asset retirement obligations related to its wind farms as a result of changes in the assumption related to the timing of removal used in the valuation of the asset retirement obligations.

Accumulated Other Comprehensive Income (Loss)

The following table summarizes changes in the components of accumulated other comprehensive loss attributable to OGE Energy during the nine months ended September 30, 2013. All amounts below are presented net of tax and noncontrolling interest.



	Pension Plan and Restoration of Retirement Income Plan					Postretirement Benefit Plans
	Net loss			Prior service cost		Net loss			Prior service cost			Deferred commodity contracts hedging gains			Deferred interest rate swap hedging losses			Less: Noncontrolling interest			Total
Balance at December 31, 2012	$	(49.3	)	$	0.1	$	(15.7	)	$	7.2		$	0.1		$	(0.5	)	$	(9.0	)	$	(49.1	)
Amounts reclassified from accumulated other comprehensive income (loss)	2.8			—		1.6			(1.4		)	0.2			0.2			0.1			3.3
Deconsolidation of Enogex Holdings	2.8			—		1.0			(0.3		)	(0.7		)	—			8.9			(6.1		)
Net current period other comprehensive income (loss)	5.6			—		2.6			(1.7		)	(0.5		)	0.2			9.0			(2.8		)
Balance at September 30, 2013	$	(43.7	)	$	0.1	$	(13.1	)	$	5.5		$	(0.4	)	$	(0.3	)	$	—		$	(51.9	)

The following table summarizes significant amounts reclassified out of accumulated other comprehensive loss by the respective line items in net income during the three and nine months ended September 30, 2013.



Details about Accumulated Other Comprehensive Loss Components	Amount Reclassified from Accumulated Other Comprehensive Income (Loss)						Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended			Nine Months Ended
	September 30, 2013			September 30, 2013
Gains (losses) on cash flow hedges
Commodity contracts	$	(0.6	)	$	(0.4	)	Cost of goods sold
Interest rate swap	(0.1		)	(0.3		)	Interest expense
	(0.7		)	(0.7		)	Total before tax
	(0.3		)	(0.3		)	Tax benefit
	$	(0.4	)	$	(0.4	)	Net of tax

Amortization of defined benefit pension items
Actuarial gains (losses)	$	(1.5	)	$	(4.6	)	(A)
Prior service cost	—			—			(A)
	(1.5		)	(4.6		)	Total before tax
	(0.6		)	(1.8		)	Tax benefit
	(0.9		)	(2.8		)	Net of tax
	—			(0.1		)	Noncontrolling interest
	$	(0.9	)	$	(2.7	)	Net of tax and noncontrolling interest

Amortization of postretirement benefit plan items
Actuarial gains (losses)	$	(0.9	)	$	(2.5	)	(A)
Prior service cost	0.8			2.2			(A)
	(0.1		)	(0.3		)	Total before tax
	—			(0.1		)	Tax benefit
	$	(0.1	)	$	(0.2	)	Net of tax

Total reclassifications for the period	$	(1.4	)	$	(3.3	)	Net of tax and noncontrolling interest


(A)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost (see Note 11 for additional information).

Forward Stock Split

On May 16, 2013, the Company's Board of Directors approved a 2-for-1 forward stock split of the Company's common stock, effective July 1, 2013, which entitled each shareholder of record to receive two shares for every one share of Company stock owned by the shareholder. In connection with the stock split, an amendment to the Company's Articles of Incorporation was approved on May 16, 2013 which increased the number of authorized shares of common stock from 225 million to 450 million. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Reclassifications

As discussed in Note 12, the former natural gas transportation and storage segment and natural gas gathering and processing segment have been combined into the natural gas midstream operations segment and have been restated for all prior periods presented. Effective May 1, 2013, the Company deconsolidated its previously held investment in Enogex Holdings and acquired an equity interest in Enable Midstream Partners.


2.	Accounting Pronouncement

In July 2013, the Emerging Issues Task Force issued "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward or Tax Credit Carryforward Exists." The new standard requires entities to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the statement of financial position as a reduction to a deferred tax asset for a net operating loss carryforward or a tax credit carryforward, except as follows. To the extent that a net operating loss carryforward or tax credit carryforward at the reporting date is not available under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, the unrecognized tax benefit would be presented in the statement of financial position as a liability. The new standard is applicable for all entities that have unrecognized tax benefits when a net operating loss carryforward or a tax credit carryforward exists. The new standard is effective for interim and annual reporting periods beginning after December 15, 2013 and does not require any new financial statement disclosures. This new standard may be applied retrospectively or prospectively with early adoption permitted. The Company retrospectively adopted this new standard effective January 1, 2013.


3.	Investment in Unconsolidated Affiliates 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 Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPoint that will initially be 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 Midstream Partners. The Company determined that its contribution of Enogex LLC to Enable Midstream Partners met the requirements of being in substance real estate and was recorded at historical cost. Enogex LLC is a provider of integrated natural gas midstream services. Enogex LLC is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex LLC's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. CenterPoint Energy Field Services, LLC, a Delaware limited liability company and, prior to the closing of the transaction on May 1, 2013, a wholly owned subsidiary of CenterPoint, that provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States, was converted into a Delaware limited partnership that became Enable Midstream Partners. CenterPoint contributed to Enable Midstream Partners its equity interests in each of (i) CenterPoint Energy Gas Transmission Company, LLC, a Delaware limited liability company that is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas, (ii) MRT, a Delaware limited liability company that is an interstate pipeline that provides natural gas transportation, storage and pipeline services to customers principally in Arkansas, Illinois and Missouri and (iii) certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute a 24.95 percent interest in Southeast Supply Header, LLC, a Delaware limited liability company. CenterPoint indirectly owned a 50 percent interest in Southeast Supply Header, LLC, which owns a 1.0 billion cubic feet per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama.

Immediately prior to closing, on May 1, 2013, the ArcLight group contributed $107.0 million and OGE Energy contributed $9.1 million to Enogex LLC in order to pay down short-term debt. At September 30, 2013, OGE Energy, through its wholly owned subsidiary OGE Holdings, holds 28.5 percent of the limited partners interests in Enable Midstream Partners.

CenterPoint has certain put rights, and Enable Midstream Partners has certain call rights, exercisable with respect to any interest in Southeast Supply Header, LLC retained by CenterPoint following the formation of Enable Midstream Partners, under which CenterPoint would contribute to Enable Midstream Partners CenterPoint's retained interest in Southeast Supply Header, LLC at a price equal to the fair market value of such interest at the time the put right or call right is exercised. If CenterPoint were to exercise such put right or Enable Midstream Partners were to exercise such call right, CenterPoint's retained interest in Southeast Supply Header, LLC would be contributed to Enable Midstream Partners in exchange for consideration consisting of a specified number of limited partnership units and, subject to certain restrictions, a cash payment, payable either from CenterPoint to Enable Midstream Partners or from Enable Midstream Partners to CenterPoint, in an amount such that the total consideration exchanged is equal in value to the fair market value of the contributed interest in Southeast Supply Header, LLC.

The general partner of Enable Midstream Partners is equally controlled by CenterPoint and OGE Energy, who each have 50 percent of the management rights. CenterPoint and OGE Energy also own a 40 percent and 60 percent interest, respectively, in any incentive distribution rights to be held by the general partner of Enable Midstream Partners following an initial public

offering of Enable Midstream Partners. In addition, for a period of time, the ArcLight group will have certain protective rights and approval rights over certain material activities of Enable Midstream Partners, including material increases in capital expenditures and certain equity issuances, entering into transactions with related parties and acquiring, pledging or disposing of certain material assets. The general partner of Enable Midstream Partners will initially be governed by a board made up of an equal number of representatives designated by each of CenterPoint Energy, Inc. and OGE Energy. Based on the 50/50 management ownership, with neither company having control, effective May 1, 2013, OGE Energy deconsolidated its interest in Enogex Holdings LLC and began accounting for its interest in Enable Midstream Partners using the equity method of accounting.

Pursuant to a Registration Rights Agreement dated as of May 1, 2013, OGE Energy and CenterPoint Energy, Inc. agreed to initiate the process for the sale of an equity interest in Enable Midstream Partners in an initial public offering. Enable Midstream Partners has agreed to file a registration statement for the initial public offering no later than May 1, 2014 and, subject to limited exceptions, consummate the initial public offering within 180 days of the filing of the registration statement. The Company currently expects that Enable Midstream Partners will file a registration statement during the fourth quarter of 2013. The initial public offering is subject to market conditions and OGE Energy can give no assurances that the initial public offering will be consummated.

Effective May 1, 2013, Enable Midstream Partners entered into a $1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's $400 million revolving credit facility was terminated.

Subject to the exceptions provided below, pursuant to the terms of an Omnibus Agreement dated as of May 1, 2013 among OGE Energy, the ArcLight group and CenterPoint Energy, Inc., each of OGE Energy and CenterPoint Energy, Inc. will be required to hold or otherwise conduct all of its respective Midstream Operations (as defined below) located within the United States in Enable Midstream Partners. This restriction will cease to apply to both OGE Energy and CenterPoint Energy, Inc. as soon as either OGE Energy or CenterPoint Energy, Inc. ceases to hold (i) any interest in the general partner of Enable Midstream Partners or (ii) at least 20 percent of the limited partner interests of Enable Midstream Partners. "Midstream Operations" generally means, subject to certain exceptions, the gathering, compression, treatment, processing, blending, transportation, storage, isomerization and fractionation of crude oil and natural gas, its associated production water and enhanced recovery materials such as carbon dioxide, and its respective constituents and the following products: methane, NGLs (Y-grade, ethane, propane, normal butane, isobutane and natural gasoline), condensate, and refined products and distillates (gasoline, refined product blendstocks, olefins, naphtha, aviation fuels, diesel, heating oil, kerosene, jet fuels, fuel oil, residual fuel oil, heavy oil, bunker fuel, cokes, and asphalts), to the extent such activities are located within the United States.

In addition, if OGE Energy or CenterPoint Energy, Inc. acquires any assets or equity of any person engaged in Midstream Operations with a value in excess of $50 million (or $100 million in the aggregate with such party's other acquired Midstream Operations that have not been offered to Enable Midstream Partners), the acquiring party will be required to offer Enable Midstream Partners the opportunity to acquire such assets or equity for such value; provided, that the acquiring party will not be obligated to offer any such assets or equity to Enable Midstream Partners if the acquiring party intends to cease using them in Midstream Operations within 12 months. If Enable Midstream Partners does not exercise its option, then the acquiring party will be free to retain and operate such Midstream Operations; provided, however, that if the fair market value of such Midstream Operations is greater than 66 2/3 percent of the fair market value of all of the assets being acquired in such transaction, then the acquiring party will be required to dispose of such Midstream Operations within 24 months.

As long as the ArcLight group has certain protective rights, the ArcLight group will be prohibited from pursuing any transaction independently from Enable Midstream Partners (i) if the ArcLight group's consent is required for Enable Midstream Partners to pursue such transaction and (ii) the ArcLight group affirmatively votes not to consent to such transaction.

On May 1, 2013, OGE Energy, OGE Holdings and Enable Midstream Partners entered into a Seconding Agreement. During the term of the Seconding Agreement, OGE Holdings' employees will continue to perform services for Enable Midstream Partners and its subsidiaries.

Distributions received from Enable Midstream Partners were $17.4 million during the three and nine months ended September 30, 2013.

Related Party Transactions

As OGE Energy's interest in Enogex Holdings was deconsolidated on May 1, 2013, operating costs charged and related party transactions between the Company and its affiliate, Enable Midstream Partners, after May 1, 2013, which were previously eliminated in consolidation, are discussed below.

OGE Energy charged operating costs to Enogex Holdings/Enable Midstream Partners of $6.6 million and $10.9 million during the three and five months ended September 30, 2013, respectively. OGE Energy charges operating costs to its subsidiaries and unconsolidated affiliates based on several factors. Operating costs directly related to specific subsidiaries and unconsolidated affiliates are assigned to those subsidiaries and unconsolidated affiliates. Where more than one subsidiary or unconsolidated affiliate benefits from certain expenditures, the costs are shared between those subsidiaries and unconsolidated affiliates receiving the benefits. Operating costs incurred for the benefit of all subsidiaries and unconsolidated affiliates are allocated among the subsidiaries and unconsolidated affiliates, either as overhead based primarily on labor costs or using the "Distrigas" method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

Related Party Transactions with Enable Midstream Partners



	Three Months Ended		Five Months Ended
	September 30,		September 30,
(In millions)	2013		2013
Operating Revenues:
Electricity to power electric compression assets	$	3.9	$	5.2
Cost of Goods Sold:
Natural gas transportation services	$	8.7	$	14.5
Natural gas storage services	3.1		5.4
Natural gas purchases (A)	9.4		11.9


(A)	At September 30, 2013, there was $1.4 million of natural gas purchases recorded for these activities.

Summarized Financial Information of Enable Midstream Partners

As Enable Midstream Partners began operations on May 1, 2013, summarized unaudited financial information for 100 percent of Enable Midstream Partners is presented below at September 30, 2013 and for the three and five months ended September 30, 2013.



Balance Sheet	September 30, 2013
	(In millions)
Current assets	$	427.5
Non-current assets	10,537.1
Current liabilities	622.1
Non-current liabilities	2,140.4



	Three Months Ended		Five Months Ended
Income Statement	September 30, 2013		September 30, 2013
	(In millions)
Operating revenues	$	796.4	$	1,298.4
Gross margin	337.1		544.5
Operating income	132.0		206.7
Net income	123.3		188.4

Enable Midstream Partners concluded that the formation of Enable Midstream Partners 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. Determining the fair value of certain

assets and liabilities assumed is judgmental in nature and often involves the use of significant estimates and assumptions. Enable Midstream Partners utilized appraisers to assist in the determination of fair value of certain assets.

OGE Energy recorded equity in earnings of unconsolidated affiliates of $46.0 million, and $64.5 million for the three and five months ended September 30, 2013, respectively. Equity in earnings of unconsolidated affiliates includes OGE Energy's 28.5 percent share of Enable Midstream Partners 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 Midstream, based on historical cost as of May 1, 2013. 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 described above.



	Three Months Ended		Five Months Ended
Reconciliation of Equity in Earnings of Unconsolidated Affiliates	September 30, 2013		September 30, 2013
	(In millions)
OGE's 28.5% share of Enable Net Income	$	35.1	$	53.6
Amortization of basis difference	5.9		5.9
Elimination of Enogex Holdings fair value adjustments	5.0		5.0
OGE's Equity in earnings of unconsolidated affiliates	$	46.0	$	64.5


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 and examples of each are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on the NYMEX and settled through a NYMEX clearing broker.

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include over-the-counter NYMEX natural gas swaps, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX pricing.

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 utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management's best estimate of fair value. These contracts are classified as Level 3.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor's Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity's choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Company has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The Company had no material financial instruments measured at fair value on a recurring basis at September 30, 2013. The following table summarizes the Company's assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012 as well as presents the Company's commodity contracts fair value included in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company adopted the FASB's accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company posted $0.2 million of collateral at December 31, 2012 which has been included within netting adjustments in the table below. The Company held no collateral at December 31, 2012. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Consolidated Balance Sheet at December 31, 2012. The Company held no Level 3 investments at December 31, 2012.



December 31, 2012
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets (B)		Liabilities (C)
Quoted market prices in active market for identical assets (Level 1)	$	5.0		$	5.0		$	—	$	—
Significant other observable inputs (Level 2)	0.5			0.5			3.1		3.8
Total fair value	5.5			5.5			3.1		3.8
Netting adjustments	(5.0		)	(5.2		)	—		—
Total	$	0.5		$	0.3		$	3.1	$	3.8


(A)	The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.


(B)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $5.9 million at December 31, 2012, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.


(C)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1.2 million at December 31, 2012, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the fair value and carrying amount of the Company's financial instruments at September 30, 2013 and December 31, 2012.



	September 30, 2013				December 31, 2012
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt
OG&E Senior Notes	$	2,154.3	$	2,455.2	$	1,904.2	$	2,401.6
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
OG&E Tinker Debt	10.4		9.1		10.7		10.0
OGE Energy Senior Notes	99.9		103.7		99.9		106.3
Enogex LLC Senior Notes	(A)		(A)		448.4		493.4
Enogex LLC Term Loan	(A)		(A)		250.0		250.0


(A)	As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company's consolidated financial statements do not include any obligations for the Enogex LLC Senior Notes and Enogex LLC Term Loan as of May 1, 2013.

The Company's long-term debt is valued 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.	Derivative Instruments and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivatives instruments is interest rate risk. The Company is also exposed to credit risk in its business operations.

Interest Rate Risk

The Company's exposure to changes in interest rates primarily relates to short-term variable-rate debt and commercial paper. The Company manages its interest rate exposure by monitoring and limiting the effects of market changes in interest rates. The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce the effects of these changes. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Credit Risk

The Company is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company's financial results could be adversely affected and the Company could incur losses.

Cash Flow Hedges

For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income (Loss) and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative's change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument. Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.

The Company previously designated as cash flow hedges derivatives for OGE Holdings' NGLs volumes and corresponding keep-whole natural gas resulting from its natural gas processing contracts (processing hedges) and natural gas positions resulting from its natural gas gathering and processing operations and natural gas transportation and storage operations (operational gas

hedges). The Company also previously designated as cash flow hedges certain derivatives for certain natural gas storage inventory positions. Due to the deconsolidation effective May 1, 2013, the Company had no material instruments designated as cash flow hedges at September 30, 2013.

Fair Value Hedges

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. The Company includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.

At September 30, 2013 and December 31, 2012, the Company had no derivative instruments that were designated as fair value hedges.

Derivatives Not Designated as Hedging Instruments

Derivative instruments not designated as hedging instruments are utilized in OGE Holdings' asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

At September 30, 2013 and December 31, 2012, the Company had no material derivative instruments that were not designated as hedging instruments.

Balance Sheet Presentation Related to Derivative Instruments

The Company had no material derivative instruments included in its Condensed Consolidated Balance Sheet at September 30, 2013. The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2012 are as follows:



		Fair Value
Instrument	Balance Sheet Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Other Current Assets	$	—	$	0.5
Total		$	—	$	0.5

Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.1	$	—
	Other Current Assets	5.0		4.7
Physical Purchases/Sales	Current PRM	0.4		0.3
Total		$	5.5	$	5.0
Total Gross Derivatives (A)		$	5.5	$	5.5


(A)	See Note 4 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2012.

Income Statement Presentation Related to Derivative Instruments

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the three months ended September 30, 2012.

Derivatives in Cash Flow Hedging Relationships



(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(0.8	)	$	—		$	—
Interest Rate Swap	—			(0.1		)	—
Total	$	(0.8	)	$	(0.1	)	$	—

Derivatives Not Designated as Hedging Instruments



(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(2.7	)
Natural Gas Financial Futures/Swaps	(0.2		)
Total	$	(2.9	)

The following tables present the effect of derivative instruments on the Company's Condensed Consolidated Statement of Income for the nine months ended September 30, 2012.

Derivatives in Cash Flow Hedging Relationships



(In millions)	Amount Recognized in Other Comprehensive Income			Amount Reclassified from Accumulated Other Comprehensive Income (Loss) into Income			Amount Recognized in Income
Natural Gas Financial Futures/Swaps	$	(1.0	)	$	5.2		$	—
Interest Rate Swap	—			(0.3		)	—
Total	$	(1.0	)	$	4.9		$	—

Derivatives Not Designated as Hedging Instruments



(In millions)	Amount Recognized in Income
Natural Gas Physical Purchases/Sales	$	(8.8	)
Natural Gas Financial Futures/Swaps	0.8
Total	$	(8.0	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income (Loss) into income (effective portion) and amounts recognized in income (ineffective portion) for the three and nine months ended September 30, 2012, if any, are reported in Operating Revenues. For derivatives not designated as hedges in the tables above, amounts recognized in income for the three and nine months ended September 30, 2012, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

At September 30, 2013 the Company had no derivative instruments that contain credit-risk related contingent features.


6.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit during the three and nine months ended September 30, 2013 and 2012 related to the Company's performance units and restricted stock.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2013		2012		2013		2012
Performance units
Total shareholder return	$	2.5	$	1.9	$	6.4	$	5.7
Earnings per share	0.6		0.7		1.9		2.0
Total performance units	3.1		2.6		8.3		7.7
Restricted stock	0.1		0.1		0.3		0.5
Total compensation expense	3.2		2.7		8.6		8.2
Less: Amount paid by unconsolidated affiliates	1.4		—		2.0		—
Net compensation expense	$	1.8	$	2.7	$	6.6	$	8.2
Income tax benefit	$	0.7	$	1.0	$	2.6	$	3.2

The Company has issued new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During the three and nine months ended September 30, 2013, there were 292 shares forfeited and 549,228 shares of new common stock issued, respectively, pursuant to the Company's stock incentive plans related to exercised stock options, restricted stock grants (net of forfeitures) and payouts of earned performance units. During the nine months ended September 30, 2013, there were 125,264 of treasury stock shares issued. During the three and nine months ended September 30, 2013, there were 4,038 shares and 10,512 shares of restricted stock, respectively, returned to the Company to satisfy tax liabilities. The Company received $1.4 million during the nine months ended September 30, 2013 related to exercised stock options. The Company did not realize an income tax benefit for the tax deductions from the exercised stock options during the three and nine months ended September 30, 2013 due to the Company being in a tax net operating loss position in 2013.

As a result of the formation of Enable Midstream Partners on May 1, 2013, 50 percent of OGE Holdings' 2013 performance unit grants that were previously based on earnings before interest, taxes, depreciation and amortization were converted to stock-based compensation. The performance unit grants converted totaled 91,390, which is comprised of 45,596 total shareholder return performance units with a $25.89 grant date fair value and 45,794 earnings per share performance units with a $26.73 grant date fair value. As a result of a modification to the 2012 performance unit grants, 50 percent of OGE Holdings' 2012 performance unit grants that were previously based on earnings before interest, taxes and depreciation and amortization were converted to stock-based compensation. The performance unit grants converted totaled 82,400 , which is comprised of 41,288 total shareholder return performance units with a $47.71 grant date fair value and 41,112 earnings per share performance units with a $34.94 grant date fair value. The amount of these performance units were adjusted for the effects of the stock split. The impact of the modification of the performance unit grants on stock-based compensation expense for the three and nine months ended September 30, 2013 was not material.


7.	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 2010 or state and local tax examinations by tax authorities for years prior to 2005. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. OG&E 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 in the Company's 2012 Form 10-K, in January 2013, OG&E 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 first quarter of 2013, OG&E recorded a reserve of $7.8 million ($5.1 million after tax) related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 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.

As a result of acquiring an equity interest in Enable Midstream Partners, the Company has a lower effective tax rate in conjunction with the formation of Enable Midstream Partners in states with lower state tax rates, which reduced income tax expense for the nine months ended September 30, 2013 by $3.9 million. In addition, deferred tax adjustments related to the Company's deconsolidation of Enogex Holdings increased income tax expense for the nine months ended September 30, 2013 by $3.9 million.

Acquisition of the equity interest in Enable Midstream Partners on May 1, 2013, is also expected to increase the Company's utilization of net operating loss carryforwards throughout 2013. The Company now projects utilization of approximately $122.0 million of Federal net operating loss carryforwards in 2013. State net operating loss utilization is expected to begin in 2014.

In the third quarter of 2013, the Company recognized a $17.1 million reduction in deferred state income taxes, associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable Midstream Partners, LP.


8.	Common Equity

Forward Stock Split

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 105,595 shares and 304,385 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months ended September 30, 2013 and received proceeds of $4.0 million and $10.4 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 September 30, 2013, there were 3,940,603 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. Basic and diluted earnings per share for the Company were calculated as follows:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2013		2012		2013		2012
Net Income Attributable to OGE Energy	$	215.2	$	185.5	$	330.0	$	316.5
Average Common Shares Outstanding
Basic average common shares outstanding	198.4		197.4		198.1		197.0
Effect of dilutive securities:
Contingently issuable shares (performance units)	1.3		0.9		1.2		0.9
Diluted average common shares outstanding	199.7		198.3		199.3		197.9
Basic Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	1.08	$	0.94	$	1.67	$	1.61
Diluted Earnings Per Average Common Share Attributable to OGE Energy Common Shareholders	$	1.08	$	0.94	$	1.66	$	1.60
Anti-dilutive shares excluded from earnings per share calculation	—		—		—		—


9.	Long-Term Debt

At September 30, 2013, 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)
0.18%	-	0.34%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.12%	-	0.39%	Muskogee Industrial Authority, January 1, 2025	32.4
0.11%	-	0.30%	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.

Issuance of Long-Term Debt

On May 8, 2013, OG&E issued $250 million of 3.9% senior notes due May 1, 2043. The proceeds from the issuance were added to OG&E's general funds and were used to repay short-term debt, fund capital expenditures, general corporate expenses and for working capital purposes. OG&E expects to issue additional long-term debt from time to time when market conditions are favorable and when the need arises.


10.	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 $447.0 million and $430.9 million at September 30, 2013 and December 31, 2012, respectively. The following table provides information regarding the Company's revolving credit agreements at September 30, 2013.



	Aggregate			Amount		Weighted-Average
Entity	Commitment			Outstanding (A)		Interest Rate			Maturity
	(In millions)
OGE Energy (B)	$	750.0		$	447.0	0.30	%	(E)	December 13, 2017	(F)
OG&E (C)	400.0			2.1		0.53	%	(E)	December 13, 2017	(F)
Total	$	1,150.0	(D)	$	449.1	0.30	%


(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at September 30, 2013.


(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)	Effective May 1, 2013, Enable Midstream Partners entered into a $1.4 billion, five-year senior unsecured revolving credit facility in accordance with the terms of the Master Formation Agreement and Enogex LLC's $400 million revolving credit facility was terminated.


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

(F)

In December 2011, the Company and OG&E entered into unsecured five-year revolving credit agreements to total in the aggregate $1,150.0 million ($750 million for the Company and $400 million for OG&E). Each of the credit facilities contain an option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013, the Company and OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of their credit agreements to December 13, 2017.

The Company's ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with the Company's credit facilities could cause annual fees and borrowing rates to increase if an adverse 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 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, 2013 and ending December 31, 2014.


11.	Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost 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						Nine Months Ended						Three Months Ended				Nine Months Ended
	September 30,						September 30,						September 30,				September 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)			2013 (B)		2012 (B)		2013 (C)		2012 (C)
Service cost	$	4.8		$	4.5		$	14.3		$	13.5		$	0.3	$	0.3	$	0.9	$	0.8
Interest cost	6.6			7.5			20.0			22.5			0.1		0.1		0.4		0.4
Expected return on plan assets	(12.1		)	(11.5		)	(36.3		)	(34.5		)	—		—		—		—
Amortization of net loss	6.6			6.0			19.8			17.9			0.1		0.1		0.3		0.3
Amortization of unrecognized prior service cost (A)	0.5			0.5			1.4			1.6			0.1		0.2		0.2		0.5
Total net periodic benefit cost	6.4			7.0			19.2			21.0			0.6		0.7		1.8		2.0
Less: Amount paid by unconsolidated affiliates	1.5			—			2.5			—			0.1		—		0.1		—
Net periodic benefit cost (net of unconsolidated affiliates)	$	4.9		$	7.0		$	16.7		$	21.0		$	0.5	$	0.7	$	1.7	$	2.0


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

(B)

In addition to the $5.4 million and $7.7 million of net periodic benefit cost recognized during the three months ended September 30, 2013 and 2012, respectively, OG&E recognized an increase in pension expense during the three months ended September 30, 2013 and 2012 of $1.5 million and $1.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are included in the Pension tracker regulatory liability (see Note 1).

(C)

In addition to the $18.4 million and $23.0 million of net periodic benefit cost recognized during the nine months ended September 30, 2013 and 2012, respectively, OG&E recognized an increase in pension expense during the nine months ended September 30, 2013 and 2012 of $4.6 million and $7.6 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						Nine Months Ended
	September 30,						September 30,
(In millions)	2013 (B)			2012 (B)			2013 (C)			2012 (C)
Service cost	$	1.1		$	1.0		$	3.3		$	3.1
Interest cost	2.5			2.9			7.7			8.9
Expected return on plan assets	(0.6		)	(0.8		)	(1.9		)	(2.3		)
Amortization of transition obligation	—			0.7			—			2.1
Amortization of net loss	5.4			5.2			16.1			15.4
Amortization of unrecognized prior service cost (A)	(4.1		)	(4.1		)	(12.4		)	(12.4		)
Total net periodic benefit cost	4.3			4.9			12.8			14.8
Less: Amount paid by unconsolidated affiliates	0.6			—			1.0			—
Net periodic benefit cost (net of unconsolidated affiliates)	$	3.7		$	4.9		$	11.8		$	14.8


(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 $3.7 million and $4.9 million of net periodic benefit cost recognized during the three months ended September 30, 2013 and 2012, respectively, OG&E recognized an increase in postretirement medical expense during the three months ended September 30, 2013 and 2012 of $0.1 million and $0.1 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 $11.8 million and $14.8 million of net periodic benefit cost recognized during the nine months ended September 30, 2013 and 2012, respectively, OG&E recognized an increase in postretirement medical expense during the nine months ended September 30, 2013 and 2012 of $0.4 million and $0.8 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).

The capitalized portion of net periodic pension benefit cost was $1.1 million and $3.7 million during the three and nine months ended September 30, 2013 as compared to $1.6 million and $4.7 million during the same period in 2012. The capitalized portion of net periodic postretirement benefit cost was $0.7 million and $2.3 million during the three and nine months ended September 30, 2013 as compared to $1.0 million and $3.0 million during the same period in 2012.

Pension Plan Funding

The Company previously reported in its 2012 Form 10-K that it may contribute up to $35 million to its Pension Plan during 2013. In May 2013, the Company contributed $35 million to its Pension Plan. No additional contributions are expected in 2013.


12.	Report of Business Segments

Prior to May 1, 2013, the Company's business was divided into three segments as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage and (iii) natural gas gathering and processing. 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 Midstream Partners to own and operate the midstream businesses of OGE Energy and CenterPoint that will initially be structured as a private limited partnership. As a result, effective May 1, 2013, OGE Energy deconsolidated its interest in Enogex Holdings LLC and began accounting for its interest in Enable Midstream Partners using the equity method of accounting. The Company's business is now divided into two segments for financial reporting purposes as follows: (i) electric utility and (ii) natural gas midstream operations. The former natural gas transportation and storage segment and natural gas gathering and processing segment have been combined into the natural gas midstream operations segment and have been restated for all prior periods presented. Equity in earnings of unconsolidated affiliates in the natural gas midstream operations segment includes OGE Energy's equity interest in Enable Midstream Partners from May 1, 2013 through September 30, 2013. Other than equity in earnings of unconsolidated affiliates, all amounts for the natural gas midstream operations segment are through April 30, 2013. Investment in unconsolidated affiliates in the natural gas midstream operations segment represents OGE Energy's investment in Enable Midstream Partners at September 30, 2013. 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. In reviewing its segment operating results, the Company focuses on operating income as its measure of segment profit and loss, and, therefore, has presented this information below. The following tables summarize the results of the Company's business segments during the three and nine months ended September 30, 2013 and 2012.



Three Months Ended September 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	723.2	$	—	$	—		$	—		$	723.2
Cost of goods sold	273.0		—		—			—			273.0
Gross margin on revenues	450.2		—		—			—			450.2
Other operation and maintenance	105.9		—		(3.7		)	—			102.2
Depreciation and amortization	62.5		—		2.9			—			65.4
Taxes other than income	20.8		—		0.9			—			21.7
Operating income (loss)	$	261.0	$	—	$	(0.1	)	$	—		$	260.9
Equity in earnings of unconsolidated affiliates	$	—	$	46.0	$	—		$	—		$	46.0

Investment in unconsolidated affiliates (at historical cost)	$	—	$	1,295.8	$	—		$	—		$	1,295.8
Total assets	$	7,704.0	$	1,311.3	$	172.2		$	(43.3	)	$	9,144.2



Three Months Ended September 30, 2012	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	721.0	$	412.4	$	—		$	(20.0	)	$	1,113.4
Cost of goods sold	271.8		288.6		—			(20.8		)	539.6
Gross margin on revenues	449.2		123.8		—			0.8			573.8
Other operation and maintenance	108.6		42.3		(3.8		)	—			147.1
Depreciation and amortization	63.5		26.5		3.0			—			93.0
Taxes other than income	19.1		9.8		0.8			—			29.7
Operating income (loss)	$	258.0	$	45.2	$	—		$	0.8		$	304.0

Total assets	$	7,082.3	$	2,562.7	$	276.6		$	(215.6	)	$	9,706.0



Nine Months Ended September 30, 2013	Electric Utility		Natural Gas Midstream Operations		Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,753.3	$	630.4	$	—		$	(24.9	)	$	2,358.8
Cost of goods sold	733.6		489.0		—			(26.0		)	1,196.6
Gross margin on revenues	1,019.7		141.4		—			1.1			1,162.2
Other operation and maintenance	318.0		60.9		(6.7		)	—			372.2
Depreciation and amortization	185.8		36.8		9.1			—			231.7
Taxes other than income	63.9		10.5		3.7			—			78.1
Operating income (loss)	$	452.0	$	33.2	$	(6.1	)	$	1.1		$	480.2
Equity in earnings of unconsolidated affiliates	$	—	$	64.5	$	—		$	—		$	64.5

Investment in unconsolidated affiliates (at historical cost)	$	—	$	1,295.8	$	—		$	—		$	1,295.8
Total assets	$	7,704.0	$	1,311.3	$	172.2		$	(43.3	)	$	9,144.2



Nine Months Ended September 30, 2012	Electric Utility		Natural Gas Midstream Operations			Other Operations			Eliminations			Total
(In millions)
Operating revenues	$	1,675.7	$	1,186.0		$	—		$	(52.6	)	$	2,809.1
Cost of goods sold	671.9		816.5			—			(54.2		)	1,434.2
Gross margin on revenues	1,003.8		369.5			—			1.6			1,374.9
Other operation and maintenance	333.9		127.3			(13.5		)	—			447.7
Depreciation and amortization	185.9		74.2			10.0			—			270.1
Impairment of assets	—		0.3			—			—			0.3
Gain on insurance proceeds	—		(7.5		)	—			—			(7.5		)
Taxes other than income	58.4		22.8			3.5			—			84.7
Operating income (loss)	$	425.6	$	152.4		$	—		$	1.6		$	579.6

Total assets	$	7,082.3	$	2,562.7		$	276.6		$	(215.6	)	$	9,706.0


13.	Commitments and Contingencies

Except as set forth below, in Note 14 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 16 and 17 to the Company's Consolidated Financial Statements included in the Company's 2012 Form 10-K appropriately represent, in all material respects, the current status of the Company's material commitments and contingent liabilities.

OG&E Minimum Fuel Purchase Commitments

OG&E has coal contracts for purchases from January 2012 through December 2016. Also, as previously reported, OG&E had entered into multiple-month term natural gas contracts for 26.1 percent of its 2013 annual forecasted natural gas requirements.

In February 2013, through a request for proposal, OG&E entered into various multiple-month term natural gas contracts for 84.0 percent of its remaining forecasted 2013 natural gas requirements. OG&E has entered into multiple-month term natural gas contracts for 25.5 percent of its 2014 annual forecasted natural gas requirements. Additional gas supplies to fulfill OG&E's remaining 2014 natural gas requirements will be acquired through additional requests for proposal in early to mid-2014, along with monthly and daily purchases, all of which are expected to be made at market prices.

OG&E Long-Term Service Agreement Commitments

OG&E has a long-term parts and service maintenance contract for the upkeep of the McClain Plant. The existing contract will expire on January 1, 2015. In May 2013, a new contract was signed that is expected to run for the earlier of 128,000 factored-fired hours or 3,600 factored-fired starts. Based on historical usage and current expectations for future usage, this contract is expected to run until 2030. The contract requires payments based on both a fixed and variable cost component, depending on how much the McClain Plant is used.

OG&E has a long-term parts and service maintenance contract for the upkeep of the Redbud Plant. In March 2013, the contract was amended to extend the contract coverage for an additional 24,000 factored-fired hours. Based on historical usage and current expectations for future usage, this contract is expected to run until 2027. The contract requires payments based on both a fixed and variable cost component, depending on how much the Redbud Plant is used.

Enable Midstream Partners Transportation Contract

Enable Midstream Partners provides gas transmission delivery services to all of PSO's natural gas-fired electric generation facilities in Oklahoma under a firm intrastate transportation contract. The PSO contract provides for a monthly demand charge plus variable transportation charges including fuel. The stated term of the PSO contract was set to expire January 1, 2014, but the contract remains in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the next succeeding annual period. Because neither party provided notice of termination 180 days prior to January 1, 2014, the PSO contract will remain in effect at least through January 1, 2015.

OGE Holdings Noncancellable Operating Leases

As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company has no obligations included in its Consolidated Financial Statements at September 30, 2013 under OGE Holdings' noncancellable lease obligations previously disclosed in the Company's 2012 Form 10-K.

Enogex Energy Resources, LLC Commitments

As a result of the formation of Enable Midstream Partners on May 1, 2013 and the Company's deconsolidation of Enogex Holdings, the Company has no obligations included in its Consolidated Financial Statements at September 30, 2013, under Enogex Energy Resources, Inc.'s commitments previously disclosed in the Company's 2012 Form 10-K.

OG&E Wind Energy Purchased Power Lawsuit

In 2009, OG&E entered into a wind energy purchase power agreement with CPV Keenan for the purchase of all the energy output from its 150 MW wind farm in Woodward County, Oklahoma. In August of 2013, CPV Keenan filed suit against OG&E for the non-payment of curtailment charges, for a non-specified amount in excess of $0.1 million. OG&E believes that it is not liable for curtailment charges in this case. Management believes the range of possible outcomes in this suit is between $0 and approximately $10 million. The Company believes that any possible losses in this case 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.

Environmental Laws and Regulations

Federal Clean Air Act New Source Review Litigation

May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that OG&E's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards.

In March 2013, the DOJ informed OG&E that it was prepared to initiate enforcement litigation concerning the matters identified in the notice of violation. OG&E subsequently met with EPA and DOJ representatives regarding the notice of violation and proposals for resolving the matter without litigation. On July 8, 2013, the United States, at the request of the EPA, filed a complaint for declaratory relief against OG&E in United States District Court for the Western District of Oklahoma (Case No. CIV-13-690-D) alleging that OG&E did not follow the Federal Clean Air Act procedures for projecting emission increases attributable to eight projects that occurred between 2003 and 2006. This complaint seeks to have OG&E submit a new assessment of whether the projects were likely to result in a significant emissions increase. The Sierra Club has intervened in this proceeding and has asserted claims for declaratory relief that are similar to those requested by the United States. OG&E expects to vigorously defend against these claims, but OG&E cannot predict the outcome of such litigation. On August 12, 2013, the Sierra Club filed a complaint against OG&E in the United States District Court for the Eastern District of Oklahoma (Case No. 13-CV-00356) alleging that OG&E modifications made at Unit 6 of the Muskogee generating plant in 2008 were made without obtaining a prevention of significant deterioration permit and that the plant has exceeded emissions limits for opacity and particulate matter. The Sierra Club seeks permanent injunction preventing OG&E from operating the Muskogee generating plant. At this time, OG&E continues to believe that it has acted in compliance with the Federal Clean Air Act.

If OG&E does not prevail in these proceedings and if a new assessment of the projects were to conclude that they caused a significant emissions increase, the EPA and the Sierra Club could seek to require OG&E to install additional pollution control equipment, including Dry Scrubbers and selective catalytic reduction systems with capital costs in excess of $1.0 billion and pay fines and significant penalties as a result of the allegations in the notice of violation. 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. The cost of any required pollution control equipment could also be significant. OG&E cannot predict at this time whether it will be legally required to incur any of these costs.

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, except as otherwise stated above, in Note 14 below, under "Environmental Laws and Regulations" in Item 2 of Part 1 and in Item 1 of Part II of this Form 10-Q, in Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I of the Company's 2012 Form 10-K, 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.


14.	Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 17 to the Company's Consolidated Financial Statements included in the Company's 2012 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters.

Completed Regulatory Matters

Crossroads Wind Farm

As previously reported, OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind farm. Also as part of this project, on June 16, 2011, OG&E entered into an interconnection agreement with the SPP for the Crossroads wind farm which allowed the Crossroads wind farm to interconnect at 227.5 megawatts. On August 31, 2012, OG&E filed an application with the APSC requesting approval to recover the Arkansas portion of the costs of the Crossroads wind farm through a rider until such costs are included in OG&E's base rates as part of its next general rate proceeding. On April 15, 2013, the APSC issued an order authorizing OG&E to recover the Arkansas portion of the cost to construct the

Crossroads wind farm, effective retroactively to August 1, 2012. The costs will be recovered through the Energy Cost Recovery Rider.

Market-Based Rate Authority

On June 29, 2012, OG&E filed its triennial market power update with the FERC to retain its market-based rate authorization in the SPP's energy imbalance service market but to surrender its market-based rate authorization for any market-based rates sales outside of the SPP's energy imbalance service market. On May 2, 2013, the FERC issued an order accepting OG&E's June 2012 triennial market power update.

Fuel Adjustment Clause Review for Calendar Year 2011

On July 31, 2012, the OCC Staff filed an application for a public hearing to review and monitor OG&E's application of the 2011 fuel adjustment clause and for a prudence review of OG&E's electric generation, purchased power and fuel procurement processes and costs in calendar year 2011. On April 9, 2013, the OCC administrative law judge recommended that the OCC find that for the calendar year 2011 OG&E's electric generation, purchased power and fuel procurement processes and costs were prudent. On June 18, 2013, the OCC issued an order approving the administrative law judge’s recommendation.

Pending Regulatory Matters

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

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

Order No. 1000 requires, among other things, public utility transmission providers, such as the SPP, to participate in a process that produces a regional transmission plan satisfying certain standards, and requires that each such regional process consider transmission needs driven by public policy requirements (such as state or Federal policies favoring increased use of renewable energy resources). Order No. 1000 also directs public utility transmission providers to coordinate with neighboring transmission planning regions. In addition, Order No. 1000 establishes specific regional cost allocation principles and directs public utility transmission providers to participate in regional and interregional transmission planning processes that satisfy these principles.

On the issue of determining how entities are to be selected to develop and construct the specific transmission projects, Order No. 1000 directs public utility transmission providers to remove from the FERC-jurisdictional tariffs and agreements provisions that establish any Federal "right of first refusal" for the incumbent transmission owner (such as OG&E) regarding transmission facilities selected in a regional transmission planning process, subject to certain limitations. However, Order No. 1000 is not intended to affect the right of an incumbent transmission owner (such as OG&E) to build, own and recover costs for upgrades to its own transmission facilities, and Order No. 1000 does not alter an incumbent transmission owner's use and control of existing rights of way. Order No. 1000 also clarifies that incumbent transmission owners may rely on regional transmission facilities to meet their reliability needs or service obligations. The SPP currently has a "right of first refusal" for incumbent transmission owners and this provision has played a role in OG&E being selected by the SPP to build various transmission projects in Oklahoma. These changes to the "right of first refusal" apply only to "new transmission facilities," which are described as those subject to evaluation or reevaluation (under the applicable local or regional transmission planning process) subsequent to the effective date of the regulatory compliance filings required by the rule, which were filed on November 13, 2012. On May 29, 2013, the Governor signed House Bill 1932 into law which establishes a right of first refusal for Oklahoma incumbent transmission owners, including OG&E, to build new transmission projects with voltages under 300 kilovolts that interconnect to those incumbent entities' existing facilities. OG&E believes this law is consistent with the language of Order No. 1000.

On July 18, 2013, the FERC issued an order on the SPP's Order No. 1000 compliance filing. This order accepted in part and rejected in part the SPP's plan for complying with Order No. 1000. The FERC rejected the SPP's plan to retain the right of first refusal for projects that would operate between 100 kilovolts and 300 kilovolts. However, the FERC clarified that a right of first refusal was appropriate in certain circumstances. It is not clear how the FERC's order will relate to the recently enacted Oklahoma law addressing a right of first refusal for lower voltages. The SPP was ordered to submit another compliance filing by November 15, 2013.

OGE Energy cannot, at this time, determine the precise impact of Order No. 1000 on OG&E. OG&E has filed a petition for review in the D.C. Circuit relating to the same matter. Nevertheless, at the present time, OGE Energy has no reason to believe that the implementation of Order No. 1000 will impact OG&E's transmission projects currently under development and construction for which OG&E has received a notice to proceed from the SPP.

Fuel Adjustment Clause Review for Calendar Year 2012

The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2013, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2012, 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 October 9, 2013. A hearing on this matter is scheduled for April 24, 2014.

Request for Modification to Previous Orders

On August 2, 2013, OG&E filed an application at the OCC seeking to make minor modifications to three previous OCC orders. The purpose of the application was to address the timing of certain requirements contained in those orders. The Company's application proposed to address these issues in OG&E's next general rate case thus avoiding the cost associated with a rate case filing now and benefiting customers by deferring the recovery of certain costs identified in the previous orders. On September 3, 2013, the PUD Staff filed a motion to dismiss OG&E's application. PUD Staff requested that the OCC dismiss OG&E's application and issue an order requiring OG&E to file a rate case for the 2012 test year.

On September 11, 2013, the PUD Staff withdrew their motion to dismiss OG&E's application and on September 12, 2013, filed an application requesting a public hearing, review and possible adjustment of the rates and charges of OG&E based on the 2012 test year. To date, no procedural schedule has been established for either the OG&E application or the PUD Staff application.

OG&E Energy Efficiency Program Filing

On October 9, 2013 OG&E filed an application with the APSC requesting approval of interim modifications to approved Energy Efficiency Programs, new tariff revisions and the waiver of certain provisions of the Commission’s Rules for Conservation and Energy Efficiency Programs.

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

Introduction

The Company is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through two business segments: (i) electric utility and (ii) natural gas midstream operations. For a discussion of the change in the Company’s business segments due to the formation of Enable Midstream Partners, see Note 12 of Notes to Condensed Consolidated Financial Statements. For periods prior to May 1, 2013, the Company consolidated Enogex Holdings in its Condensed Consolidated Financial Statements.

As discussed in Note 1 of Notes to Condensed Consolidated Financial Statements, the Company completed a 2-for-1 stock split of the Company's common stock effective July 1, 2013. All share and per share amounts within this Form 10-Q have been retroactively adjusted to reflect the effects of the stock split for all periods presented.

Overview

Company Strategy

The Company's mission is to fulfill its critical role in the nation's electric utility and natural gas midstream pipeline infrastructure, through its equity interest in Enable Midstream Partners, 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 unregulated natural gas midstream business, through its equity interest in Enable Midstream Partners, while providing competitive energy products and services to customers primarily in the south central United States 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 of five to seven percent on a weather-normalized basis, maintaining a strong credit rating as well as increasing the dividend to meet the Company's dividend payout objectives. The Company's target payout ratio is to pay out dividends no more than 60 percent of its normalized earnings on an annual basis. The target payout ratio 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, the composition of the Company's assets and investment opportunities. 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 September 30, 2013 as Compared to Three Months Ended September 30, 2012

Net income attributable to OGE Energy was $215.2 million, or $1.08 per diluted share, during the three months ended September 30, 2013 as compared to $185.5 million, or $0.94 per diluted share, during the same period in 2012. The increase in net income attributable to OGE Energy of $29.7 million, or 16.0 percent, during the three months ended September 30, 2013 as compared to the same period in 2012 was primarily due to:


•	an increase in net income at OG&E of $4.3 million, or 2.6 percent, or $0.02 per diluted share of the Company's common stock, primarily due to higher other income and lower other operation and maintenance expense, partially offset by higher income tax expense and taxes other than income;

•

an increase in net income attributable to OGE Holdings of $27.9 million, or $0.14 per diluted share of the Company's common stock, due to the accretive effect to OGE Holdings of Enable Midstream Partners for the entire quarter and a reduction in deferred state income taxes, associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable Midstream Partners, LP.; and


•	a decrease in net income attributable to OGE Energy of $2.5 million, or $0.02 per diluted share of the Company's common stock, primarily due to losses associated with valuation differences between the deferred compensation assets and liabilities for investments that are based on the Company's common stock.

Nine Months Ended September 30, 2013 as Compared to Nine Months Ended September 30, 2012

Net income attributable to OGE Energy was $330.0 million, or $1.66 per diluted share, during the nine months ended September 30, 2013 as compared to $316.5 million, or $1.60 per diluted share, during the same period in 2012. The increase in net income attributable to OGE Energy of $13.5 million, or 4.3 percent, during the nine months ended September 30, 2013 as compared to the same period in 2012 was primarily due to:


•	an increase in net income at OG&E of $10.8 million, or 4.3 percent, or $0.04 per diluted share of the Company's common stock, primarily due to a higher gross margin and lower other operation and maintenance expense, partially offset by higher income taxes and taxes other than income;


•	an increase in net income attributable to OGE Holdings of $9.1 million, or 14.3 percent, or $0.05 per diluted share of the Company's common stock, due to the accretive effect to OGE Holdings of Enable Midstream Partners for five of the nine months presented, a reduction in deferred state income taxes, associated with a remeasurement

of the accumulated deferred taxes related to the formation of Enable Midstream Partners, LP., and increased gathering rates and volumes and inlet processing volumes associated with ongoing Enogex LLC expansion projects and the gas gathering assets acquired in August 2012. These increases were partially offset by lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex LLC's five largest customers from keep-whole to fixed-fee, in addition to slightly higher other operation and maintenance expense and depreciation and amortization expense; and

•

a decrease in net income attributable to OGE Energy of $6.4 million, or $0.03 per diluted share of the Company's common stock, primarily due to transaction expenses related to the formation of Enable Midstream Partners as discussed in Note 3 of Notes to Condensed Consolidated Financial Statements and losses associated with valuation differences between the deferred compensation assets and liabilities for investments that are based on the Company's common stock, partially offset by a decrease in income taxes.

Regulatory Matter

Enable Midstream Partners FERC Rate Proceeding

In August 2012, MRT, a subsidiary of Enable Midstream Partners and an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Illinois and Missouri, made a rate filing with the FERC pursuant to Section 4 of the Natural Gas Act. In its filing, MRT requested an annual cost of service of $103.8 million (an increase of approximately $47.3 million above the annual cost of service underlying the current FERC approved maximum rates for MRT's pipeline), new depreciation rates, an overall rate of return of 10.813 percent (based on a return on equity of 13.62 percent), a regulatory compliance cost surcharge with a true-up mechanism to recover safety, environmental, and security costs associated with mandated requirements and billing determinants reflecting no adjustments for MRT's conversion of a portion of Enable Gas Transmission, LLC's (formerly CenterPoint Energy Gas Transmission Company, LLC) firm capacity to a lease. On July 30, 2013, MRT filed with the FERC an uncontested Stipulation and Agreement and Offer of Settlement, resolving all issues in the rate case. In particular, MRT withdrew its proposed regulatory compliance cost surcharge. The settlement specifies few particulars, other than setting an annual overall cost-of-service for MRT of $84.0 million and increasing the depreciation rates for certain asset classes. In September, 2013, the FERC approved the settlement. Although the settlement became effective November 1, 2013, the settlement rates were effective as of March 1, 2013. As a result, MRT will be making refunds to certain of its customers for amounts collected between the requested $103.8 million cost of service and the $84.0 million settlement cost of service, which amounts had already been reserved by Enable Midstream Partners.

2013 Outlook

The Company's 2013 consolidated earnings guidance has been increased from between $335 million to $360 million of net income, or $1.68 to $1.80 per average diluted share to between $360 million and $380 million of net income, or $1.80 to $1.90 per average diluted share and assumes approximately 200 million average share outstanding (adjusted for the stock split). OG&E's and the holding company's 2013 earnings guidance are unchanged and assume normal weather for the remainder of the year. See the Company's 2012 Form 10-K for other key factors and assumptions underlying its 2013 earnings guidance.

Key assumptions for 2013 include:

Natural Gas Midstream Operations

The Company has increased projected earnings from Natural Gas Midstream Operations from between $70 million and $90 million of net income or $0.35 to $0.45 per average diluted share to between $90 million to $100 million, or $0.45 to $0.50 per average diluted share. The increase is based primarily on the formation of Enable Midstream Partners, LP.

Results of Operations

The following discussion and analysis presents factors that affected the Company's consolidated results of operations for the three and nine months ended September 30, 2013 as compared to the same period in 2012 and the Company's consolidated financial position at September 30, 2013. Due to seasonal fluctuations and other factors, the Company's operating results for the three and nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013 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				Nine Months Ended
	September 30,				September 30,
(In millions except per share data)	2013		2012		2013		2012
Operating income	$	260.9	$	304.0	$	480.2	$	579.6
Net income attributable to OGE Energy	$	215.2	$	185.5	$	330.0	$	316.5
Basic average common shares outstanding	198.4		197.4		198.1		197.0
Diluted average common shares outstanding	199.7		198.3		199.3		197.9
Basic earnings per average common share attributable to OGE Energy common shareholders	$	1.08	$	0.94	$	1.67	$	1.61
Diluted earnings per average common share attributable to OGE Energy common shareholders	$	1.08	$	0.94	$	1.66	$	1.60
Dividends declared per common share	$	0.20875	$	0.19625	$	0.62625	$	0.58875

In reviewing its consolidated operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Consolidated Statements of Income, as operating income indicates the ongoing profitability of the Company excluding the cost of capital and income taxes.

Operating Income by Business Segment



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2013			2012		2013			2012
OG&E (Electric Utility)	$	261.0		$	258.0	$	452.0		$	425.6
OGE Holdings (Natural Gas Midstream Operations) (A)	—			45.2		33.2			152.4
Other Operations (B)	(0.1		)	0.8		(5.0		)	1.6
Consolidated operating income	$	260.9		$	304.0	$	480.2		$	579.6

(A)

The former natural gas transportation and storage segment and natural gas gathering and processing segment have been combined into the natural gas midstream operations segment and have been restated for all prior periods presented. The natural gas midstream operations reported equity in earnings of unconsolidated affiliates of $46.0 million and $64.5 million during the three and nine months ended September 30, 2013, respectively.


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

The following operating income analysis by business segment includes intercompany transactions that are eliminated in the Condensed Consolidated Financial Statements.

OG&E (Electric Utility)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(Dollars in millions)	2013		2012			2013		2012
Operating revenues	$	723.2	$	721.0		$	1,753.3	$	1,675.7
Cost of goods sold	273.0		271.8			733.6		671.9
Gross margin on revenues	450.2		449.2			1,019.7		1,003.8
Other operation and maintenance	105.9		108.6			318.0		333.9
Depreciation and amortization	62.5		63.5			185.8		185.9
Taxes other than income	20.8		19.1			63.9		58.4
Operating income	261.0		258.0			452.0		425.6
Allowance for equity funds used during construction	1.7		1.3			4.4		4.9
Other income (loss)	2.9		(0.3		)	6.4		5.7
Other expense	0.5		2.2			1.3		3.5
Interest expense	31.6		31.2			96.0		93.2
Income tax expense	62.0		58.4			102.0		86.8
Net income	$	171.5	$	167.2		$	263.5	$	252.7
Operating revenues by classification
Residential	$	307.6	$	321.7		$	709.9	$	707.1
Commercial	176.2		170.2			428.2		404.1
Industrial	66.8		63.2			171.0		158.5
Oilfield	51.1		48.5			135.9		125.8
Public authorities and street light	67.7		64.9			165.3		155.0
Sales for resale	15.9		16.0			45.7		41.9
System sales revenues	685.3		684.5			1,656.0		1,592.4
Off-system sales revenues	5.8		15.5			11.2		29.5
Other	32.1		21.0			86.1		53.8
Total operating revenues	$	723.2	$	721.0		$	1,753.3	$	1,675.7
Megawatt-hour sales by classification (In millions)
Residential	2.9		3.2			7.2		7.3
Commercial	2.0		2.1			5.3		5.4
Industrial	1.1		1.0			3.0		3.0
Oilfield	0.9		0.8			2.5		2.5
Public authorities and street light	0.9		0.9			2.4		2.5
Sales for resale	0.4		0.4			1.0		1.0
System sales	8.2		8.4			21.4		21.7
Off-system sales	0.1		0.5			0.3		1.1
Total sales	8.3		8.9			21.7		22.8
Number of customers	804,521		796,696			804,521		796,696
Weighted-average cost of energy per kilowatt-hour - cents
Natural gas	3.758		2.939			3.838		2.822
Coal	2.290		2.354			2.293		2.295
Total fuel	2.746		2.554			2.792		2.403
Total fuel and purchased power	3.077		2.839			3.164		2.755
Degree days (A)
Heating - Actual	3		7			2,168		1,464
Heating - Normal	19		19			2,020		2,020
Cooling - Actual	1,418		1,630			2,018		2,484
Cooling - Normal	1,380		1,380			2,018		2,018

(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 September 30, 2013 as Compared to Three Months Ended September 30, 2012

OG&E's operating income increased $3.0 million, or 1.2 percent, during the three months ended September 30, 2013 as compared to the same period in 2012 primarily due to lower other operation and maintenance expense, and to a lesser extent higher gross margin and lower depreciation and amortization, partially offset by higher taxes other than income.

Gross Margin

Operating revenues were $723.2 million during the three months ended September 30, 2013 as compared to $721.0 million during the same period in 2012, an increase of $2.2 million, or 0.3 percent. Cost of goods sold was $273.0 million during the three months ended September 30, 2013 as compared to $271.8 million during the same period in 2012, an increase of $1.2 million, or 0.4 percent. Gross margin was $450.2 million during the three months ended September 30, 2013 as compared to $449.2 million during the same period in 2012, an increase of $1.0 million, or 0.2 percent. The below factors contributed to the change in gross margin:



	$ Change
	(In millions)
Wholesale transmission revenue (A)	$	11.0
New customer growth	4.0
Price variance (B)	2.0
Non-residential demand and related revenues	0.9
Other	0.1
Quantity variance (primarily weather)	(17.0		)
Change in gross margin	$	1.0


(A)	Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.


(B)	Decreased primarily due to sales and customer mix and timing of the Oklahoma rate increase.

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $200.0 million during the three months ended September 30, 2013 as compared to $212.7 million during the same period in 2012, a decrease of $12.7 million, or 6.0 percent, primarily due to lower natural gas generation partially offset by higher gas prices. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. Purchased power costs were $66.6 million during the three months ended September 30, 2013 as compared to $55.8 million during the same period in 2012, an increase of $10.8 million, or 19.4 percent, primarily due to an increase in purchases in the energy imbalance service market and short term power agreements. Transmission-related charges were $6.4 million during the three months ended September 30, 2013 as compared to $3.3 million during the same period in 2012, an increase of $3.1 million, or 93.9 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, 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 Midstream Partners.

Operating Expenses

Other operation and maintenance expense was $105.9 million during the three months ended September 30, 2013 as compared to $108.6 million during the same period in 2012, a decrease of $2.7 million, or 2.5 percent. The below factors contributed to the change in other operation and maintenance expense:



	$ Change
	(In millions)
Employee benefits (A)	$	(3.7	)
Incentive compensation expense	(1.9		)
Ongoing maintenance at power plants (B)	(1.3		)
Other	(0.2		)
Capitalized labor	4.4
Change in other operation and maintenance expense	$	(2.7	)


(A)	Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case and a decrease in worker's compensation accruals.


(B)	Decreased due to delay in timing of outages to later in 2013.

Depreciation and amortization expense was $62.5 million during the three months ended September 30, 2013 as compared to $63.5 million during the same period in 2012, a decrease of $1.0 million, or 1.6 percent, primarily due to the amortization of the deferred Pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1). These decreases in depreciation and amortization expense were partially offset by:


•	changes in depreciation rates from the August 2012 rate case; and


•	additional assets being placed in service throughout 2012 and the nine months ended September 30, 2013, including the smart grid project which was completed in late 2012 and the Cleveland to Sooner transmission project which was fully in service in February 2013.

Taxes other than income was $20.8 million during the three months ended September 30, 2013 as compared to $19.1 million during the same period in 2012, an increase of $1.7 million, or 8.9 percent, primarily due to higher ad valorem taxes.

Additional Information

Other Income. Other income was $2.9 million during the three months ended September 30, 2013 as compared to a net loss of $0.3 million during the same period in 2012, an increase of $3.2 million, primarily due to an increased margin of $3.0 million recognized in the guaranteed flat bill program in 2013 as a result of lower usage.

Other Expense. Other expense was $0.5 million during the three months ended September 30, 2013 as compared to $2.2 million during the same period in 2012, a decrease of $1.7 million, or 77.3 percent primarily due to a decrease in charitable contributions.

Interest Expense. Interest expense was $31.6 million during the three months ended September 30, 2013 as compared to $31.2 million during the same period in 2012, an increase of $0.4 million, or 1.3 percent, primarily due to a $2.5 million increase in interest on long term debt related to a $250 million debt issuance that occurred in May 2013, partially offset by a $2.0 million decrease in interest related to tax matters.

Income Tax Expense. Income tax expense was $62.0 million during the three months ended September 30, 2013 as compared to $58.4 million during the same period in 2012, an increase of $3.6 million or 6.2 percent, primarily due to higher pre-tax income during the three months ended September 30, 2013 as compared to the same period in 2012.

Nine Months Ended September 30, 2013 as Compared to Nine Months Ended September 30, 2012

OG&E's operating income increased $26.4 million, or 6.2 percent, during the nine months ended September 30, 2013 as compared to the same period in 2012 primarily due to a higher gross margin and lower other operation and maintenance expense, partially offset by higher income taxes and taxes other than income.

Gross Margin

Operating revenues were $1,753.3 million during the nine months ended September 30, 2013 as compared to $1,675.7 million during the same period in 2012, an increase of $77.6 million, or 4.6 percent. Cost of goods sold was $733.6 million during the nine months ended September 30, 2013 as compared to $671.9 million during the same period in 2012, an increase of $61.7 million, or 9.2 percent. Gross margin was $1,019.7 million during the nine months ended September 30, 2013 as compared to $1,003.8 million during the same period in 2012, an increase of $15.9 million, or 1.6 percent. The below factors contributed to the change in gross margin:



	$ Change
	(In millions)
Wholesale transmission revenue (A)	$	31.6
New customer growth	9.2
Non-residential demand and related revenues	0.6
Other	(0.1		)
Price variance (B)	(6.1		)
Quantity variance (primarily weather)	(19.3		)
Change in gross margin	$	15.9


(A)	Increased primarily due to higher investments related to certain FERC approved transmission projects included in formula rates.


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

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $517.3 million during the nine months ended September 30, 2013 as compared to $501.6 million during the same period in 2012, an increase of $15.7 million, or 3.1 percent, primarily due to higher natural gas prices partially offset by lower gas and coal generation. OG&E's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers. Purchased power costs were $197.4 million during the nine months ended September 30, 2013 as compared to $160.6 million during the same period in 2012, an increase of $36.8 million, or 22.9 percent, primarily due to an increase in purchases in the energy imbalance service market and short term power agreements. Transmission-related charges were $18.9 million during the nine months ended September 30, 2013 as compared to $9.7 million during the same period in 2012, an increase of $9.2 million, or 94.8 percent, primarily due to higher SPP charges for the base plan projects of other utilities.

Operating Expenses

Other operation and maintenance expense was $318.0 million during the nine months ended September 30, 2013 as compared to $333.9 million during the same period in 2012, a decrease of $15.9 million, or 4.8 percent. The below factors contributed to the change in other operation and maintenance expense:



	$ Change
	(In millions)
Employee benefits (A)	$	(9.8	)
Ongoing maintenance at power plants (B)	(7.0		)
Total salaries and wages (C)	(5.2		)
Corporate overheads and allocations (D)	(1.6		)
Temporary labor	(1.4		)
Contract professional services (primarily smart grid)	(1.0		)
Other	0.6
Software expense (primarily smart grid)	1.3
Administrative and assessment fees (primarily SPP and North American Electric Reliability Corporation)	2.0
Capitalized labor	6.2
Change in other operation and maintenance expense	$	(15.9	)


(A)	Decreased primarily due to lower recoverable amounts of pension expense and postretirement medical expense allowed in the August 2012 rate case, a decrease in medical expense, and a decrease in worker's compensation accruals.


(B)	Decreased due to delay in timing of outages to later in 2013.


(C)	Decreased primarily due to lower salaries and wages as a result of lower headcount in 2013 and a decrease in incentive pay, partially offset by annual salary increases and an increase in overtime wages related to May 2013 storms.


(D)	Decreased primarily due to decreases in depreciation expense and contract technical expense partially offset by an increase in salaries and wages from the holding company.

Depreciation and amortization expense was $185.8 million during the nine months ended September 30, 2013 as compared to $185.9 million during the same period in 2012, a decrease of $0.1 million, or 0.1 percent, primarily due to the amortization of the deferred Pension credits regulatory liability and a decrease in the amortization of the storm regulatory asset (see Note 1). These decreases in depreciation and amortization expense were partially offset by:


•	changes in depreciation rates from the August 2012 rate case; and


•	additional assets being placed in service throughout 2012 and the nine months ended September 30, 2013, including the Sooner-Rose Hill and Sunnyside-Hugo transmission projects, which were fully in service in April 2012, the smart grid project which was completed in late 2012 and the Cleveland to Sooner transmission project which was fully in service in February 2013.

Taxes other than income was $63.9 million during the nine months ended September 30, 2013 as compared to $58.4 million during the same period in 2012, an increase of $5.5 million, or 9.4 percent, primarily due to higher ad valorem taxes.

Additional Information

Other Income. Other income was $6.4 million during the nine months ended September 30, 2013 as compared to $5.7 million during the same period in 2012, an increase of $0.7 million, or 12.3 percent, primarily due to an increased margin of $0.8 million recognized in the guaranteed flat bill program in 2013 as a result of lower usage.

Other Expense. Other expense was $1.3 million during the nine months ended September 30, 2013 as compared to $3.5 million during the same period in 2012, a decrease of $2.2 million, or 62.9 percent primarily due to a decrease in charitable contributions.

Interest Expense. Interest expense was $96.0 million during the three months ended September 30, 2013 as compared to $93.2 million during the same period in 2012, an increase of $2.8 million, or 3.0 percent, primarily due to a $3.9 million increase in interest on long term debt related to a $250 million debt issuance that occurred in May 2013, partially offset by a $2.0 million decrease in interest related to tax matters.

Income Tax Expense. Income tax expense was $102.0 million during the nine months ended September 30, 2013 as compared to $86.8 million during the same period in 2012, an increase of $15.2 million, or 17.5 percent primarily due to higher pre-tax income and a reserve related to a portion of the Oklahoma investment tax credits generated in years prior to 2013 but not yet utilized.

OGE Holdings (Natural Gas Midstream Operations)



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2013		2012		2013		2012
Operating revenues	$	—	$	412.4	$	630.4	$	1,186.0
Cost of goods sold	—		288.6		489.0		816.5
Gross margin on revenues	—		123.8		141.4		369.5
Other operation and maintenance	—		42.3		60.9		127.3
Depreciation and amortization	—		26.5		36.8		74.2
Impairment of assets	—		—		—		0.3
Gain on insurance proceeds	—		—		—		(7.5		)
Taxes other than income	—		9.8		10.5		22.8
Operating income	—		45.2		33.2		152.4
Equity in earnings of unconsolidated affiliates	46.0		—		64.5		—
Other income	—		0.4		10.2		0.6
Other expense	—		1.2		1.3		1.9
Interest expense	—		8.7		10.6		23.7
Income tax expense	0.2		11.0		16.5		38.9
Net income	45.8		24.7		79.5		88.5
Less: Net income attributable to noncontrolling interests	—		6.8		6.6		24.7
Net income attributable to OGE Holdings	$	45.8	$	17.9	$	72.9	$	63.8

Effective May 1, 2013, the Company deconsolidated its previously held investment in Enogex Holdings and acquired a 28.5 percent equity interest in Enable Midstream Partners which is being accounted for using the equity method of accounting. The former natural gas transportation and storage segment and natural gas gathering and processing segment have been combined into the natural gas midstream operations segment and have been restated for all prior periods presented. All financial statement line items included in the table above (except equity in earnings of unconsolidated affiliates and income tax expense) reflect 2013 operations only through April 30, 2013 and are not comparable to the prior year due to the deconsolidation discussed above.

Three Months Ended September 30, 2013 as Compared to Three Months Ended September 30, 2012



	Enable Midstream Partners (Equity Method - Three Months Ended September 30, 2013)		Natural Gas Midstream Operations (Consolidated - Three Months Ended September 30, 2012)
(In millions)
Gross margin on revenues	$	—	$	123.8
Operating expenses	—		78.6
Operating income	—		45.2
Equity in earnings of unconsolidated affiliates	46.0		—
Income tax expense	0.2		11.0
Net income	45.8		17.9

Nine Months Ended September 30, 2013 as Compared to Nine Months Ended September 30, 2012



	Natural Gas Midstream Operations (Consolidated - Four Months Ended April 30, 2013)		Enable Midstream Partners (Equity Method - Five Months Ended September 30, 2013)		Total (Nine Months Ended September 30, 2013)		Natural Gas Midstream Operations (Consolidated - Nine Months Ended September 30, 2012)
(In millions)
Gross margin on revenues	$	141.4	$	—	$	141.4	$	369.5
Operating expenses	108.2		—		108.2		217.1
Operating income	33.2		—		33.2		152.4
Equity in earnings of unconsolidated affiliates	—		64.5		64.5		—
Income tax expense	9.4		7.1		16.5		38.9
Net income	15.5		57.4		72.9		63.8

OGE Holdings' results of operations for the four months ended April 2013 as compared to the same period of 2012 decreased due to lower NGLs prices, lower keep-whole processing spreads and the contract conversion of the Texas production volumes of one of Enogex LLC's five largest customers from keep-whole to fixed-fee, in addition to slightly higher other operation and maintenance expense and depreciation and amortization expense. These decreases were partially offset by increased gathering rates and volumes and inlet processing volumes associated with ongoing Enogex LLC expansion projects and the gas gathering assets acquired in August 2012.

Enable Midstream Partners' results for the three and five months ended September 30, 2013, were consistent with management's expectations in light of lower natural gas liquids prices and low seasonal and geographic price differentials. Enable Midstream Partners' continued to increase processing volumes through system expansions. Transportation throughput was impacted by system integrity projects and slightly lower demand. Gathering throughput was slightly lower, impacted by well connects.

Income taxes during the three months ended September 30, 2013 as compared to the same period in 2012 decreased due to a $17.1 million reduction in deferred state income taxes, associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable Midstream Partners, LP. partially offset by higher pre-tax income (net of noncontrolling interest). Income taxes during the nine months ended as compared to the same period in 2012 decreased due to the reduction in deferred state income taxes, associated with a remeasurement of the accumulated deferred taxes related to the formation of Enable Midstream Partners, LP. partially offset by, deferred tax adjustments related to the Company's deconsolidation of Enogex Holdings and lower pre-tax income (net of noncontrolling interest).

Enable Midstream Partners Results of Operations during the Three and Five Months Ended September 30, 2013



	Three Months Ended		Five Months Ended
	September 30, 2013		September 30, 2013
	(In millions)
Gross margin	$	337.1	$	544.5
Operating income	132.0		206.7
Net income	123.3		188.4

Equity in earnings of unconsolidated affiliates includes OGE Energy's 28.5 percent share of Enable Midstream Partners 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 Midstream, based on historical cost as of May 1, 2013. 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.

Reconciliation of Equity in Earnings of Unconsolidated Affiliates



	Three Months Ended		Five Months Ended
	September 30, 2013		September 30, 2013
	(In millions)
OGE's 28.5% share of Enable Net Income	$	35.1	$	53.6
Amortization of basis difference	5.9		5.9
Elimination of Enogex Holdings fair value adjustments	5.0		5.0
OGE's Equity in earnings of unconsolidated affiliates	$	46.0	$	64.5

Enable Midstream Partners Operating Data during the Three and Five Months Ended September 30, 2013



	Three Months Ended	Five Months Ended
	September 30, 2013	September 30, 2013

Gathered volumes - TBtu/d (A)	3.5	3.5
Transportation volumes - TBtu/d	5.1	5.2
Natural gas processed - TBtu/d	1.5	1.5


(A)	Excludes volumes billed under throughput agreements.

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 2012 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 $336.9 million and $352.7 million at September 30, 2013 and December 31, 2012, respectively, a decrease of $15.8 million, or 4.5 percent, primarily due to the deconsolidation of Enogex Holdings on May 1, 2013 partially offset by an increase in OG&E's billings to customers reflecting warmer weather and higher seasonal rates in September 2013 as compared to December 2012.

The balance of Accounts Payable was $171.1 million and $396.7 million at September 30, 2013 and December 31, 2012, respectively, a decrease of $225.6 million, or 56.9 percent, primarily due to the deconsolidation of Enogex Holdings on May 1, 2013 and a decrease due to the timing of ad valorem payments in December 2012.

Cash Flows



	Nine Months Ended
	September 30,						2013 vs. 2012
(In millions)	2013			2012			$ Change			% Change
Net cash provided from operating activities	$	351.2		$	678.0		$	(326.8	)	(48.2	)%
Net cash used in investing activities	(739.4		)	(836.6		)	97.2			11.6	%
Net cash provided from financing activities	386.4			164.2			222.2			*

Operating Activities

The decrease of $326.8 million, or 48.2 percent, in net cash provided from operating activities during the nine months ended September 30, 2013 as compared to the same period in 2012 was primarily due to:


•	fuel refunds at OG&E during the nine months ended September 30, 2013 as compared to higher fuel recoveries in the same period in 2012; and


•	the deconsolidation of Enogex Holdings on May 1, 2013.

These decreases in net cash provided from operating activities were partially offset by an increase in cash received during the nine months ended September 30, 2013 from transmission revenue.

Investing Activities

The decrease of $97.2 million, or 11.6 percent, in net cash used in investing activities during the nine months ended September 30, 2013 as compared to the same period in 2012 was primarily due to lower levels of capital expenditures due to the deconsolidation of OGE Holdings and proceeds received from OGE Holdings' sale of certain gas gathering assets in the Texas Panhandle partially offset by higher levels of capital expenditures during the nine months ended September 30, 2013 related to various transmission projects at OG&E.

Financing Activities

The increase of $222.2 million in net cash provided from financing activities during the nine months ended September 30, 2013 as compared to the same period in 2012 was primarily due to:


•	a decrease in repayments of lines of credit during the nine months ended September 30, 2013 as compared to the same period in 2012;


•	payments on advances from unconsolidated affiliates due to the deconsolidation of Enogex Holdings on May 1, 2013; and


•	and a contribution of $107.0 million from the Arclight group immediately prior to the closing of the transaction to form Enable Midstream Partners.

These increases in net cash provided from financing activities are partially offset by a decrease in short-term debt borrowings during the nine months ended September 30, 2013 as compared to the same period in 2012.

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. OGE Energy believes that Enable Midstream Partners has, or will have access to, adequate liquidity and, therefore, no contributions are expected to be necessary to fund the capital expenditures of Enable Midstream Partners from the general partners. Accordingly, capital expenditures for Enable Midstream Partners are not included in the table below.

Capital Expenditures

The Company's consolidated estimates of capital expenditures for the years 2013 through 2017 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.



(In millions)	2013		2014		2015		2016		2017
OG&E Base Transmission	$	55	$	30	$	30	$	30	$	30
OG&E Base Distribution	175		175		175		175		175
OG&E Base Generation	100		135		75		75		75
OG&E Other	15		15		15		15		15
Total OG&E Base Transmission, Distribution, Generation and Other	345		355		295		295		295
OG&E Known and Committed Projects:
Transmission Projects:
Regionally Allocated Base Projects (A)	50		50		20		20		20
Balanced Portfolio 3E Projects (B)(C)	190		15		—		—		—
SPP Priority Projects (B)(C)	185		70		—		—		—
SPP Integrated Transmission Projects (B) (C)	5		10		—		40		40
Total Transmission Projects	430		145		20		60		60
Other Projects:
Smart Grid Program	25		25		10		10		—
System Hardening	15		—		—		—		—
Environmental - low NOX burners	20		25		25		20		—
Total Other Projects	60		50		35		30		—
Total OG&E Known and Committed Projects	490		195		55		90		60
Total OG&E (D)	835		550		350		385		355
OGE Energy	10		15		10		10		10
Total capital expenditures	$	845	$	565	$	360	$	395	$	365

(A)Approximately 30% of revenue requirement allocated to SPP members other than OG&E.

(B)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
	Balanced Portfolio 3E	135 miles of transmission line from OG&E's Seminole substation to OG&E's Muskogee substation	$165	Late 2013
	Balanced Portfolio 3E	96 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the Oklahoma /Texas Stateline to a companion transmission line to its Tuco substation	$115	Mid-2014
	Priority Project	99 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to the western Beaver County line to a companion transmission line to its Hitchland substation	$165	Mid-2014
	Priority Project	77 miles of transmission line from OG&E's Woodward District Extra High Voltage substation to a companion transmission line at the Kansas border	$140	Late 2014
	Integrated Transmission Project	47 miles of transmission line from OG&E's Gracemont substation to a 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)	The capital expenditures above exclude any environmental expenditures associated with:


•	Pollution control equipment related to controlling SO₂ emissions under the regional haze requirements due to the uncertainty regarding the approach and timing for such pollution control equipment. The SO₂ emissions standards in the EPA's FIP could require the installation of Dry Scrubbers or fuel switching. OG&E estimates that installing such Dry

Scrubbers could cost more than $1.0 billion. The FIP is being challenged by OG&E and the state of Oklahoma. On June 22, 2012, OG&E was granted a stay of the FIP by the U.S. Court of Appeals for the Tenth Circuit. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On September 3, 2013, OG&E and the state of Oklahoma filed with the Tenth Circuit a request for a rehearing; additionally 17 state attorney generals joined in to support the requested rehearing. By order dated October 31, 2013, the Tenth Circuit three-judge panel that decided the original appeal denied the petitions for rehearing by a 2 to 1 vote. OG&E believes that the stay remains in effect until after the mandate is issued by the Tenth Circuit or further order of the court. The EPA has notified OG&E that it is of the opinion the stay lifted after the Tenth Circuit’s July 19, 2013 ruling. OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP. OG&E is reviewing its additional appeal options, including a request for review of the case by the U. S. Supreme Court. As noted above, compliance with the FIP could require capital costs of more than $1.0 billion.

•

Installation of control equipment for compliance with MATS by a deadline of April 16, 2015, with the possibility of a one-year extension. OG&E is currently planning to utilize activated carbon injection and low levels of dry sorbent injection at each of its five coal-fired units. OG&E continues to review the specifications for the control equipment to be installed for compliance with MATS and has requested a one-year extension for complying or until April 16, 2016. Current costs for installing the necessary control equipment are estimated to range from $10 million to $20 million per unit.

OG&E is currently evaluating options to comply with environmental requirements. For further information, see "Environmental Laws and Regulations" below.

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

Contractual Obligations

Except as set forth below, the circumstances set forth in Contractual Obligations in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the Company's 2012 Form 10-K appropriately represent, in all material respects, the current status of the Company's contractual obligations.



(In millions)	2013		2014-2015		2016-2017		After 2017		Total
Other purchase obligations and commitments
OG&E long-term service agreement commitments	$	19.0	$	77.0	$	5.0	$	136.7	$	237.7

Pension and Postretirement Benefit Plans

In accordance with ASC Topic 715, "Compensation - Retirement Benefits," a one-time settlement charge is required to be recorded by an organization when lump sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost. During the first nine months of 2013 as compared to the first nine months of recent years, the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement in 2013. As a result, and based in part on the Company’s historical experience regarding eligible employees who elect to retire in the last quarter of a particular year, the Company currently expects that it could be required to record a pension settlement charge for 2013 of between $19 million and $25 million in the fourth quarter of 2013. Whether the Company will be required to take a pension settlement charge for 2013 will depend on numerous factors, including the amount of lump sum payments owed to employees who elect to retire during the balance of 2013. A pension settlement charge, if incurred, would not require a cash outlay by the Company and would not increase the Company’s total pension expense over time, as the charge would be an acceleration of costs that otherwise would be recognized as pension expense in future periods.

Pension Plan Funding

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 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.

In conjunction with the closing of Enable Midstream Partners on May 1, 2013, on May 2, 2013, Standard & Poor's Ratings Services upgraded the long-term senior unsecured rating of OGE Energy to BBB+ and OG&E to A-. All other security ratings as previously reported in the Company's 2012 Form 10-K remain unchanged.

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 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 September 30, 2013, the Company has revolving credit facilities totaling in the aggregate $1,150 million. These bank facilities can also be used as letter of credit facilities. The short-term debt balance was $447.0 million and $430.9 million at September 30, 2013 and December 31, 2012, respectively. The weighted-average interest rate on short-term debt at September 30, 2013 was 0.30 percent. The average balance of short-term debt during the three months ended September 30, 2013 was $459.8 million at a weighted-average interest rate of 0.31 percent. The maximum month-end balance of short-term debt during the three months ended September 30, 2013 was $515.6 million. At September 30, 2013, there was $2.1 million supporting letters of credit at a weighted-average interest rate of 0.53 percent. At September 30, 2013, the Company had $700.9 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, 2013 and ending December 31, 2014. At September 30, 2013, the Company had less than $0.1 million in cash and cash equivalents. See Note 10 of Notes to Condensed Consolidated Financial Statements for a discussion of the Company's short-term debt activity.

In December 2011, the Company and OG&E entered into unsecured five-year revolving credit agreements to total in the aggregate $1,150 million ($750 million for the Company and $400 million for OG&E). Each of the credit facilities contain an option, which may be exercised up to two times, to extend the term for an additional year, subject to consent of a specified percentage of the lenders. Effective July 29, 2013, the Company and OG&E utilized one of these one-year extensions, and received consent from all of the lenders, to extend the maturity of their credit agreements to December 13, 2017.

Issuance of Long-Term Debt

Quarterly Distributions by Enable Midstream Partners

Pursuant to the Enable Midstream Partners Agreement, during the third quarter Enable Midstream Partners made distributions of approximately $17.4 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), income taxes, contingency reserves, asset retirement obligations and the allowance for uncollectible accounts receivable. For the electric utility segment, the most significant judgment is also exercised in the valuation of regulatory assets and liabilities and unbilled revenues. For the natural gas midstream operations segment, the most significant judgment is also exercised in the valuation of operating revenues, natural gas purchases, purchase and sale contracts, assets and depreciable lives of property, plant and equipment, amortization methodologies related to intangible assets and impairment assessments of goodwill and equity method investments. 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 2012 Form 10-K.

Commitments and Contingencies

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, except as otherwise stated in Notes 13 and 14 of Notes to Condensed Consolidated Financial Statements, under "Environmental Laws and Regulations" below and in Item 1 of Part II of this Form 10-Q, in Notes 16 and 17 of Notes to Consolidated Financial Statements and Item 3 of Part I of the Company's 2012 Form 10-K, 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.

Environmental Laws and Regulations

The activities of OG&E are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E's business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of 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 2012 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

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous sources over a wide geographic area. The regional haze rule is intended to protect visibility in certain national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita Mountains are the only area covered under the rule. However, Oklahoma's impact on parks in other states must also be evaluated.

As required by the Federal regional haze rule, the state of Oklahoma evaluated the installation of BART to reduce emissions that cause or contribute to regional haze from certain sources within the state that were built between 1962 and 1977. Certain of OG&E’s units at the Horseshoe Lake, Seminole, Muskogee and Sooner generating stations were evaluated for BART. On February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state's plan for compliance with the Federal regional haze rule. The SIP was subject to the EPA's review and approval.

The Oklahoma SIP included requirements for reducing emissions of NOX and 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 NOX emissions at all of the subject units should be the installation of low NOX burners with overfire air (flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits. OG&E preliminarily estimates that the total capital cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be approximately $90 million. With respect to SO₂emissions, the SIP included an agreement between the Oklahoma Department of Environmental Quality and OG&E that established BART for SO₂ control at the four affected coal-fired units located at OG&E's Sooner and Muskogee generating stations as the continued use of low sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of Dry Scrubbers as BART for SO₂ control from these units because the state determined that Dry Scrubbers were not cost effective on these units.

On December 28, 2011, the EPA issued a final rule in which it rejected portions of the Oklahoma SIP and issued a FIP in their place. While the EPA accepted Oklahoma's BART determination for NOX in the final rule, it rejected Oklahoma's SO₂ BART determination with respect to the four coal-fired units at the Sooner and Muskogee generating stations. The EPA is instead requiring that OG&E meet an SO₂ emission rate of 0.06 pounds per million British thermal unit within five years. OG&E could meet the proposed standard by either installing and operating Dry Scrubbers or fuel switching at the four affected units. OG&E estimates that installing Dry Scrubbers on these units would include capital costs to OG&E of more than $1.0 billion. OG&E and the state of Oklahoma filed an administrative stay request with the EPA on February 24, 2012. The EPA has not yet responded to this request. OG&E and other parties also filed a petition for review of the FIP in the U.S. Court of Appeals for the Tenth Circuit on February 24, 2012 and a request to stay the FIP on April 4, 2012. On June 22, 2012, the U.S. Court of Appeals for the Tenth Circuit granted the stay request. On July 19, 2013, the U.S. Court of Appeals for the Tenth Circuit by a 2 to 1 vote denied the petition for review and affirmed the EPA's issuance of the FIP. On September 3, 2013, OG&E and the state of Oklahoma filed with the Tenth Circuit a request for a rehearing; additionally 17 state attorney generals joined in to support the requested rehearing. By order dated October 31, 2013, the Tenth Circuit three-judge panel that decided the original appeal denied the petitions for rehearing by a 2 to 1 vote. OG&E believes that the stay remains in effect until after the mandate is issued by the Tenth Circuit or further order of the court. The EPA has notified OG&E that it is of the opinion the stay lifted after the Tenth Circuit’s July 19, 2013 ruling. OG&E will have approximately 55 months from the effective date of the lifting of the stay to achieve compliance with the FIP. OG&E is reviewing its additional appeal options, including a request for review of the case by the U. S. Supreme Court. As noted above, compliance with the FIP could require capital costs of more than $1.0 billion.

Cross-State Air Pollution Rule

As previously reported, on July 7, 2011, the EPA finalized its Cross-State Air Pollution Rule to replace the former Clean Air Interstate Rule that was remanded by a Federal court as a result of legal challenges. The final rule would require 27 states to reduce power plant emissions that contribute to ozone and particulate matter pollution in other states. On December 27, 2011, the EPA published a supplemental rule, which would make six additional states, including Oklahoma, subject to the Cross-State Air Pollution Rule for NOX emissions during the ozone-season from May 1 through September 30. Under the rule, OG&E would have been required to reduce ozone-season NOX emissions from its electrical generating units within the state beginning in 2012. The Cross-State Air Pollution Rule was challenged in court by numerous states and power generators. On December 30, 2011, the U.S. Court of Appeals issued a stay of the rule, which includes the supplemental rule, pending a decision on the merits. By order dated August 21, 2012, the U.S. Court of Appeals vacated the Cross-State Air Pollution Rule and ordered the EPA to

promulgate a replacement rule. On June 24, 2013, the U.S. Supreme Court agreed to review the decision by the U.S. Court of Appeals, with a decision expected during the first half of 2014. OG&E cannot predict the outcome of such challenges.

Hazardous Air Pollutants Emission Standards

As previously reported, 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. In addition, the regulations include work practice standards for dioxins and furans. Compliance is required within three years after the effective date of the rule with the possibility of a one-year extension. To comply with this rule, OG&E is currently planning to utilize activated carbon injection and low levels of dry sorbent injection at each of its five coal-fired units. OG&E continues to review the specifications for the control equipment to be installed for compliance with MATS and has requested a one-year extension for complying or until April 16, 2016. Current costs for installing the necessary control equipment are estimated to range from $10 million to $20 million per unit. The final MATS rule has been appealed by several parties. OG&E is not a party to the appeals and cannot predict the outcome of any such appeals.

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. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act's new source review process. In January 2012, OG&E received a supplemental request for an update of the previously provided information and for some additional information not previously requested. On May 1, 2012, OG&E responded to the EPA's supplemental request for information. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects occurred at OG&E's Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that OG&E's visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards.

Climate Change and Greenhouse Gas Emissions

There is continuing discussion and evaluation of possible global climate change in certain regulatory and legislative arenas. The focus is generally on emissions of greenhouse gases, including carbon dioxide, sulfur hexafluoride and methane, and whether these emissions are contributing to the warming of the Earth's atmosphere. There are various international agreements that restrict greenhouse gas emissions, but none of them have a binding effect on sources located in the United States. The U.S. Congress has not passed legislation to reduce emissions of greenhouse gases and the future prospects for any such legislation are uncertain, but the EPA has existing authority under the Clean Air Act to regulate greenhouse gas emissions from stationary sources. Several states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Oklahoma and Arkansas are not among them. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on the Company's facilities, this could result in significant additional compliance costs that would affect the Company’s future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

In September 2013, the EPA issued proposed New Source Performance Standards (NSPS) that specify permissible levels of greenhouse gas emissions from newly-constructed fossil fuel-fired electric generating units. The proposed NSPS sets separate standards for natural gas combined cycle units and coal-fired generating units. As directed by President Obama's June 25, 2013, Climate Action Plan, the EPA also announced plans to establish, pursuant to Section 111(d) of the Clean Air Act, carbon dioxide emissions standards for existing fossil fuel fired electric generating units. EPA plans to publish the proposed standards for existing units by June 1, 2014, and finalize those guidelines by June 1, 2015. States must then submit their individual plans for reducing power plants' greenhouse gas emissions to EPA by June 30, 2016. Thus, it is possible that existing power plants may be required to comply with greenhouse gas performance standards as soon as July 2016.

In October 2013, the U.S. Supreme Court granted certiorari to review EPA's greenhouse gas regulations, including the Tailoring Rule which limits the sources subject to greenhouse gas permitting requirements to the largest fossil-fueled power plants. It is conceivable that the Court could invalidate EPA's prevention of significant deterioration and Title V Tailoring Rule, but still leave power plants subject to anticipated new and existing source performance standards for greenhouse gas emissions.

Endangered Species

Certain Federal laws, including the Bald and Golden Eagle Protection Act, the Migratory Bird Treaty Act and the Endangered Species Act, provide special protection to certain designated species. These laws and any state equivalents provide for significant civil and criminal penalties for unpermitted activities that result in harm to or harassment of certain protected animals and plants, including damage to their habitats. If such species are located in an area in which the Company conducts operations, or if additional species in those areas become subject to protection, the Company’s operations and development projects, particularly transmission, wind or pipeline projects, could be restricted or delayed, or the Company could be required to implement expensive mitigation measures. The U.S. Fish and Wildlife Service announced a proposed rule to list the lesser prairie chicken as threatened on November 30, 2012. A final decision regarding listing is anticipated to be completed by March 30, 2014. Although the lesser prairie chicken and its habitat are located in potential development areas of the Company, the impact of a final decision to list this species as threatened cannot be determined at this time.

Water

OG&E's operations are subject to the Federal Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and Federal waters. The discharge of pollutants, including discharges resulting from a spill or leak, is prohibited unless authorized by a permit or other agency approval. The Federal Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Existing cooling water intake structures are regulated under the Federal Clean Water Act to minimize their impact on the environment.

With respect to cooling water intake structures, Section 316(b) of the Federal Clean Water Act requires that their location, design, construction and capacity reflect the best available technology for minimizing their adverse environmental impact via the impingement and entrainment of aquatic organisms. In March 2011, the EPA proposed rules to implement Section 316(b). On August 18, 2011, OG&E filed comments with the EPA on the proposed rules. In June 2012, the EPA published a Notice of Data Availability requesting additional comments on a number of impingement mortality-related issues based on new information received during the initial public comment period. On July 11, 2012, OG&E filed comments regarding the Notice of Data Availability. In July 2012, the EPA entered into a settlement agreement in a pending litigation matter, which extended the deadline by which the proposed rules will be finalized to June 2013. On June 27, 2013 the EPA signed an amendment to the previous

settlement agreement to finalize the proposed rules by November 4, 2013, which date was extended to November 20, 2013 due to the federal government shutdown. In the interim, the state of Oklahoma requires OG&E to implement best management practices related to the operation and maintenance of its existing cooling water intake structures as a condition of renewing its discharge permits. Once the EPA promulgates the final rules, OG&E may incur additional capital and/or operating costs to comply with them. The costs of complying with the final water intake standards are not currently determinable, but could be significant.

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 2012 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. The Company has an investment in an unconsolidated affiliate (see Note 3 of Notes to Condensed Consolidated Financial Statements). As the Company does not control this affiliate, its disclosure controls and procedures with respect to such affiliate is more limited than those the Company maintains with respect to its consolidated subsidiaries. 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 2012 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.

Except as discussed below, there have been no significant changes in the Company's risk factors from those discussed in the Company's 2012 Form 10-K, which are incorporated herein by reference.

Enable Midstream Partners may not be able to successfully integrate the operations of OGE Holdings and CenterPoint.

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 Midstream Partners. CenterPoint Energy Field Services, LLC was converted into a Delaware limited partnership that became Enable Midstream Partners. CenterPoint contributed to Enable Midstream Partners its equity interests in each of (i) CenterPoint Energy Gas Transmission Company, LLC, (ii) MRT, and (iii) certain of its other midstream subsidiaries and caused its subsidiary CenterPoint Energy Southeastern Pipelines Holding, LLC to contribute a 24.95 percent interest in Southeast Supply Header, LLC. If Enable Midstream Partners is not able to successfully integrate these operations, it could have an adverse impact on our financial position, results of operations or cash flows.

Effective May 1, 2013, OGE Energy does not control Enogex Holdings LLC or Enable Midstream Partners, and therefore is not able to cause or prevent certain actions by Enable Midstream Partners.

Enable Midstream Partners has its own governing board, and OGE Energy will not control all of the decisions of that board. Consequently, OGE Energy will be unable solely to cause Enable Midstream Partners to take actions that OGE Energy

believes would be in our or Enable Midstream Partners' best interests. Likewise, OGE Energy will be unable to prevent certain actions of Enable Midstream Partners.

The Company's operating cash flow is derived partially from cash distributions the Company receives from its unconsolidated affiliate.

The Company's operating cash flow is derived partially from cash distributions the Company receives from its unconsolidated affiliate. The amount of cash that the Company's unconsolidated affiliate can distribute principally depends upon the amount of cash flow this affiliate generates from its operations, which may fluctuate from quarter to quarter. The Company does not have any direct control over the cash distribution policies of the Company's unconsolidated affiliate.

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 third quarter of 2013.



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
7/1/13 - 7/31/13	—		$	—		N/A	N/A
8/1/13 - 8/31/13	—		$	—		N/A	N/A
9/1/13 - 9/30/13	4,038	(A)(B)	$	35.00	(B)	N/A	N/A


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


(B)	These shares of restricted stock and the average price paid per share were adjusted for the effects of the stock split.

Item 5. Other Information

On July 26, 2013, the Company adopted a severance plan for certain officers of the Company or one its subsidiaries whose employment has been seconded to Enable GP, LLC or Enable Midstream Partners, LP. Under the terms of the plan, if a participant’s employment with the Company and its affiliates, including Enable GP, LLC and Enable Midstream Partners, LP, is terminated for reasons other than death, Disability (as defined therein) or Cause (as defined therein) prior to December 31, 2014, such participant is entitled, subject to limited exceptions, to severance benefits.

If the terminated participant has not received an offer from the Company or any affiliate of Comparable Employment With Relocation (as defined therein) as of his or her termination date such participant will be entitled to a lump-sum cash severance benefit in an amount equal to (i) 52 weeks of the participant’s weekly compensation plus (ii) such participant’s target award under the Company’s short-term incentive plan.

If the terminated participant has received and declined an offer from the Company or any affiliate of Comparable Employment With Relocation as of his or her termination date such participant shall be entitled to a lump sum cash severance benefit in an amount equal to (i) two (2) weeks of the participant’s weekly compensation multiplied by the number of full years of service credited to the participant as of his or her termination date, provided that such cash severance benefit shall not be less than 12 weeks of the participant’s weekly compensation nor more than 36 weeks of the participant’s weekly compensation and (ii) such participant’s target award under the Company’s short-term incentive plan, if any, adjusted on a pro rata basis based on the number of months the participant was actually employed during such plan year.

The participant also is entitled to continued medical, dental and vision benefits (provided that such participant is eligible for and timely elects continuation of coverage in accordance with the Consolidated Omnibus Budget Reconciliation Act of 1985 (“COBRA”) for the applicable period required by COBRA. A participant has not received an offer from the Company or any affiliate of Comparable Employment With Relocation as of his or her termination date will be entitled to receive outplacement services, not to exceed a maximum of nine months, provided the participant initiates such services within 60 days of his or her termination date.

Lump-sum cash severance payments under the plan will be made within 60 days of the date of termination, provided the participant has timely returned an executed waiver and release.

A copy of the severance plan is filed as exhibit 10.03 to this Form 10-Q.

On November 5, 2013, OGE Holdings entered into a retention agreement with E. Keith Mitchell, the Chief Operating Officer of Enable Midstream Partners, LP (the “Partnership”). Pursuant to the terms of the retention agreement, Mr. Mitchell will be entitled to receive a retention benefit of $500,000 if he (A) is continuously employed by OGE Holdings or the Partnership, the general partner of the Partnership or an affiliate of the Partnership or the general partner (a “Successor Employer”) as of January 2, 2016, (B) is terminated by OGE Holdings or a Successor Employer without Cause (as defined therein) prior to January 2, 2016 or (C) ceases to be employed by OGE Holdings or a Successor Employer prior to January 2, 2016 due to his death or Disability (as defined therein) (in each case, the “Vesting Date”). If Mr. Mitchell’s employment is terminated prior to the Vesting Date (i) by OGE Holdings or a Successor Employer for Cause or (ii) by Mr. Mitchell other than due to death or Disability, then Mr. Mitchell will not be entitled to receive the retention benefit.

If Mr. Mitchell is eligible for the retention benefit under clause (A) or (C) above, the benefit will be paid in a lump sum within 10 days of the Vesting Date. If Mr. Mitchell is eligible for the retention benefit under clause (B) above and executes and returns (and does not revoke) a waiver and release no later than 50 days after the Vesting Date, the benefit will be paid in a lump sum no later than the 60^th day following the Vesting Date. The retention benefit is in addition to, and not in lieu of, all other accrued or vested or earned compensation, rights, options or benefits payable under any retirement plan, bonus, savings or other compensation plan, stock incentive plan, life insurance plan, health plan, or disability plan or any amounts otherwise payable to Mr. Mitchell under the severance plan discussed above.

A copy of the retention agreement is filed as exhibit 10.04 to this Form 10-Q

Item 6. Exhibits.



Exhibit No.	Description
10.01	Amendment No. 4 to the Company's Deferred Compensation Plan
10.02	OGE Energy Corp. Involuntary Severance Benefits Plans for Non-Officers (Applicable only to non-officers of Enogex LLC seconded to Enable Midstream Partners, LP or Enable GP, LLC or one of its subsidiaries
10.03	OGE Energy Corp. Involuntary Severance Benefits Plans for Officers (Applicable only to officers of Enogex LLC seconded to Enable Midstream Partners, LP or Enable GP, LLC or one of its subsidiaries
10.04	Retention Agreement effective as of October 24, 2013, by and between OGE Enogex Holdings, LLC and E. Keith Mitchell.
10.05	Letter of extension dated as of July 29, 2013 for the Company's credit agreement dated as of December 13, 2011, by and between OGE Energy, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents, related to the Company's credit agreement dated December 13, 2011 (Filed as Exhibit 10.01 to OGE Energy's Form 8-K filed August 2, 2013 (File No. 1-12579) and incorporated by reference herein)
10.06	Letter of extension dated as of July 29, 2013 for OG&E's credit agreement dated as of December 13,2011, by and between OG&E, the Lenders thereto, Wells Fargo Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, N.A., as Syndication Agent, Mizuho Corporate Bank, Ltd., The Royal Bank of Scotland PLC, UBS Securities LLC and Union Bank, N.A., as Co-Documentation Agents, related to the OG&E's credit agreement dated December 13, 2011 (Filed as Exhibit 10.02 to OGE Energy's Form 8-K filed August 2, 2013 (File No. 1-12579) and incorporated by reference herein)
31.01	Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Schema Document.
101.PRE	XBRL Taxonomy Presentation Linkbase Document.
101.LAB	XBRL Taxonomy Label Linkbase Document.
101.CAL	XBRL Taxonomy Calculation Linkbase Document.
101.DEF	XBRL Definition Linkbase Document.

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)

November 6, 2013