Edgar Filing: OGE ENERGY CORP.

OGE 3RD QTR 11

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2011

£ 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. R Yes £ 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). R Yes £ 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 R	Accelerated filer £
Non-accelerated filer £ (Do not check if a smaller reporting company)	Smaller reporting company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

£ Yes R No

At September 30, 2011, there were 98,056,722 shares of common stock, par value $0.01 per share, outstanding.

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OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS



	Page

GLOSSARY OF TERMS	ii

FORWARD-LOOKING STATEMENTS	1


Part I – FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	2
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4
Condensed Consolidated Balance Sheets	5
Condensed Consolidated Statements of Changes in Stockholders' Equity	7
Notes to Condensed Consolidated Financial Statements	8

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3. Quantitative and Qualitative Disclosures About Market Risk	54

Item 4. Controls and Procedures	55

Part II – OTHER INFORMATION

Item 1. Legal Proceedings	55

Item 1A. Risk Factors	56

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	57

Item 6. Exhibits	57

Signature	58

Table of Contents

GLOSSARY OF TERMS

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



Abbreviation	Definition
2010 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2010
APSC	Arkansas Public Service Commission
ArcLight group	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
Atoka	Atoka Midstream LLC joint venture
BART	Best Available Retrofit Technology
Company	OGE Energy, collectively with its subsidiaries
Cordillera	Cordillera Energy Partners III, LLC
Crossroads	OG&E's Crossroads wind project in Dewey County, Oklahoma
Dry Scrubbers	Dry flue gas desulfurization units with Spray Dryer Absorber
Enogex	OGE Holdings, collectively with its subsidiaries
Enogex LLC	Enogex LLC, collectively with its subsidiaries
Enogex Holdings	Enogex Holdings LLC, the parent company of Enogex LLC and a majority-owned subsidiary of OGE Holdings
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States
MEP	Midcontinent Express Pipeline, LLC
MMcf/d	Million cubic feet per day
NAAQS	National Ambient Air Quality Standards
NGLs	Natural gas liquids
NOX	Nitrogen oxide
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
ODEQ	Oklahoma Department of Environmental Quality
OER	OGE Energy Resources LLC, wholly-owned subsidiary of Enogex LLC
Off-system sales	Sales to other utilities and power marketers
OG&E	Oklahoma Gas and Electric Company
OGE Holdings	OGE Enogex Holdings, LLC, wholly-owned subsidiary of OGE Energy and parent company of Enogex Holdings
Oxbow	Oxbow Midstream, LLC
Pension Plan	Qualified defined benefit retirement plan
PRM	Price risk management
Products	Enogex Products LLC, wholly-owned subsidiary of Enogex LLC
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to OG&E's customers
Windspeed	OG&E's transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma

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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 2010 Form 10-K and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:


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


•	the ability of the Company and its subsidiaries to access the capital markets and obtain financing on favorable terms;


•	prices and availability of electricity, coal, natural gas and NGLs, each on a stand-alone basis and in relation to each other as well as the processing contract mix between percent-of-liquids, percent-of-proceeds, keep-whole and fixed-fee;


•	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;


•	whether OG&E can successfully implement its Smart Grid program to install meters for its customers and integrate the Smart Grid meters with its customer billing and other computer information systems;


•	advances in technology;


•	creditworthiness of suppliers, customers and other contractual parties;


•	the higher degree of risk associated with the Company's nonregulated business compared with the Company's regulated utility business; 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 2010 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.

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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)	2011			2010			2011			2010
OPERATING REVENUES
Electric Utility operating revenues	$	774.8		$	723.0		$	1,765.6		$	1,679.8
Natural Gas Midstream Operations operating revenues	437.3			402.4			1,265.1			1,208.6
Total operating revenues	1,212.1			1,125.4			3,030.7			2,888.4
COST OF GOODS SOLD (exclusive of depreciation and amortization shown below)
Electric Utility cost of goods sold	322.7			299.4			772.7			757.2
Natural Gas Midstream Operations cost of goods sold	335.8			313.2			969.1			932.0
Total cost of goods sold	658.5			612.6			1,741.8			1,689.2
Gross margin on revenues	553.6			512.8			1,288.9			1,199.2
OPERATING EXPENSES
Other operation and maintenance	147.4			142.4			432.3			401.0
Depreciation and amortization	77.1			73.7			225.8			215.2
Impairment of assets	5.0			—			5.0			—
Taxes other than income	24.4			22.5			76.0			70.5
Total operating expenses	253.9			238.6			739.1			686.7
OPERATING INCOME	299.7			274.2			549.8			512.5
OTHER INCOME (EXPENSE)
Interest income	0.2			—			0.4			—
Allowance for equity funds used during construction	5.9			2.6			16.1			7.2
Other income	(2.2		)	0.6			11.1			5.8
Other expense	(6.4		)	(2.7		)	(12.2		)	(8.8		)
Net other income (expense)	(2.5		)	0.5			15.4			4.2
INTEREST EXPENSE
Interest on long-term debt	37.4			36.3			108.6			103.3
Allowance for borrowed funds used during construction	(2.9		)	(1.3		)	(8.1		)	(3.5		)
Interest on short-term debt and other interest charges	1.0			1.4			3.6			4.7
Interest expense	35.5			36.4			104.1			104.5
INCOME BEFORE TAXES	261.7			238.3			461.1			412.2
INCOME TAX EXPENSE	80.3			74.8			140.7			145.6
NET INCOME	181.4			163.5			320.4			266.6
Less: Net income attributable to noncontrolling interests	2.7			0.4			13.9			2.0
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	178.7		$	163.1		$	306.5		$	264.6
BASIC AVERAGE COMMON SHARES OUTSTANDING	98.0			97.4			97.9			97.3
DILUTED AVERAGE COMMON SHARES OUTSTANDING	99.3			99.0			99.2			98.8
BASIC EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	1.82		$	1.67		$	3.13		$	2.72
DILUTED EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	1.80		$	1.65		$	3.09		$	2.68
DIVIDENDS DECLARED PER COMMON SHARE	$	0.3750		$	0.3625		$	1.1250		$	1.0875

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2011			2010			2011			2010
Net income	$	181.4		$	163.5		$	320.4		$	266.6
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.3 million, $0.4
million, $1.2 million and $1.4 million, respectively	0.7			0.6			1.7			1.6
Amortization of prior service cost, net of tax of $0, $0.1 million, $0
and $0.1 million, respectively	0.1			0.1			0.3			0.2
Postretirement plans:
Amortization of deferred net loss, net of tax of $0.2 million, $0.2
million, $0.8 million and $0.2 million, respectively	0.5			0.3			1.3			1.2
Amortization of deferred net transition obligation, net of tax of $0, $0,
$0 and $0.1 million, respectively	—			—			0.1			0.3
Amortization of prior service cost, net of tax of ($0.2) million, $0,
($0.8) million and ($0.1) million, respectively	(0.5		)	—			(1.4		)	(0.2		)
Prior service cost arising during the period, net of tax of $0, $0, $6.2
million and $0, respectively	—			—			10.7			—
Deferred commodity contracts hedging losses reclassified in net income,
net of tax of $3.4 million, $2.1 million, $10.3 million and $7.3 million,
respectively	6.7			3.4			20.2			11.6
Deferred commodity contracts hedging gains (losses), net of tax of $0.1
million, ($6.6) million, ($2.7) million and ($5.6) million, respectively	0.2			(10.4		)	(6.3		)	(9.0		)
Deferred interest rate swaps hedging gains, net of tax of $0, $0, $0.2
million and $0.1 million, respectively	—			—			0.2			0.1
Other comprehensive income (loss), net of tax	7.7			(6.0		)	26.8			5.8
Comprehensive income (loss)	189.1			157.5			347.2			272.4
Less: Comprehensive income attributable to noncontrolling interest
for sale of equity investment	—			—			(1.7		)	—
Less: Comprehensive income attributable to noncontrolling interests	4.2			0.4			17.7			2.0
Total comprehensive income (loss) attributable to OGE Energy	$	184.9		$	157.1		$	331.2		$	270.4

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended
	September 30,
(In millions)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	320.4		$	266.6
Adjustments to reconcile net income to net cash provided from operating activities
Depreciation and amortization	225.8			215.2
Impairment of assets	5.0			—
Deferred income taxes and investment tax credits, net	146.1			146.8
Allowance for equity funds used during construction	(16.1		)	(7.2		)
(Gain) loss on disposition and abandonment of assets	(2.8		)	0.9
Stock-based compensation expense	3.4			4.9
Excess tax benefit on stock-based compensation	—			(0.7		)
Price risk management assets	0.1			2.3
Price risk management liabilities	12.0			6.2
Regulatory assets	9.6			15.4
Regulatory liabilities	0.6			(10.3		)
Other assets	(5.4		)	5.4
Other liabilities	(41.3		)	(10.9		)
Change in certain current assets and liabilities
Accounts receivable, net	(118.5		)	(48.0		)
Accrued unbilled revenues	(9.8		)	(11.2		)
Income taxes receivable	(3.6		)	141.2
Fuel, materials and supplies inventories	61.5			(12.3		)
Gas imbalance assets	(0.1		)	—
Fuel clause under recoveries	(32.2		)	(0.6		)
Other current assets	7.1			7.8
Accounts payable	(40.9		)	(13.7		)
Gas imbalance liabilities	(1.1		)	(1.0		)
Fuel clause over recoveries	(21.4		)	(119.5		)
Other current liabilities	30.3			9.6
Net Cash Provided from Operating Activities	528.7			586.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during construction)	(907.3		)	(612.5		)
Reimbursement of capital expenditures	37.2			24.5
Proceeds from sale of assets	17.8			1.9
Other investing activities	—			0.1
Net Cash Used in Investing Activities	(852.3		)	(586.0		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	246.3			246.2
Increase in short-term debt	144.0			49.0
Contributions from noncontrolling interest partners	73.5			—
Issuance of common stock	11.0			13.5
Proceeds from line of credit	—			115.0
Excess tax benefit on stock-based compensation	—			0.7
Retirement of long-term debt	—			(289.2		)
Distributions to noncontrolling interest partners	(12.8		)	—
Repayment of line of credit	(25.0		)	(80.0		)
Dividends paid on common stock	(110.1		)	(105.7		)
Net Cash Provided from (Used in) Financing Activities	326.9			(50.5		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	3.3			(49.6		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2.3			58.1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5.6		$	8.5

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30,		December 31,
	2011		2010
(In millions)	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5.6	$	2.3
Accounts receivable, less reserve of $2.4 and $1.9, respectively	396.4		277.9
Accrued unbilled revenues	66.6		56.8
Income taxes receivable	8.3		4.7
Fuel inventories	91.0		158.8
Materials and supplies, at average cost	89.6		83.3
Price risk management	1.8		1.4
Gas imbalances	2.6		2.5
Deferred income taxes	13.8		18.7
Fuel clause under recoveries	33.2		1.0
Other	17.6		24.7
Total current assets	726.5		632.1
OTHER PROPERTY AND INVESTMENTS, at cost	45.4		44.9
PROPERTY, PLANT AND EQUIPMENT
In service	9,569.3		9,188.0
Construction work in progress	874.7		460.0
Total property, plant and equipment	10,444.0		9,648.0
Less accumulated depreciation	3,295.2		3,183.6
Net property, plant and equipment	7,148.8		6,464.4
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets	415.3		489.4
Price risk management	0.3		0.8
Other	42.5		37.5
Total deferred charges and other assets	458.1		527.7
TOTAL ASSETS	$	8,378.8	$	7,669.1

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)



	September 30,			December 31,
	2011			2010
(In millions)	(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt	$	289.0		$	145.0
Accounts payable	297.4			321.7
Dividends payable	36.8			36.6
Customer deposits	68.0			67.0
Accrued taxes	61.6			39.3
Accrued interest	35.1			53.1
Accrued compensation	54.0			43.3
Price risk management	6.9			16.8
Gas imbalances	5.6			6.7
Fuel clause over recoveries	8.5			29.9
Other	71.3			55.1
Total current liabilities	934.2			814.5
LONG-TERM DEBT	2,586.9			2,362.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations	241.5			372.4
Deferred income taxes	1,599.8			1,434.8
Deferred investment tax credits	6.9			9.4
Regulatory liabilities	223.2			193.1
Price risk management	0.1			—
Deferred revenues	39.1			36.7
Other	48.2			45.3
Total deferred credits and other liabilities	2,158.8			2,091.7
Total liabilities	5,679.9			5,269.1
COMMITMENTS AND CONTINGENCIES (NOTE 15)
STOCKHOLDERS' EQUITY
Common stockholders' equity	999.6			969.2
Retained earnings	1,576.8			1,380.6
Accumulated other comprehensive loss, net of tax	(35.5		)	(60.2		)
Total OGE Energy stockholders' equity	2,540.9			2,289.6
Noncontrolling interests	158.0			110.4
Total stockholders' equity	2,698.9			2,400.0
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	8,378.8		$	7,669.1

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

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OGE ENERGY CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

(Unaudited)



			Premium						Accumulated
			on						Other
	Common		Common			Retained			Comprehensive			Noncontrolling
(In millions)	Stock		Stock			Earnings			Income (Loss)			Interest			Total
Balance at December 31, 2010	$	1.0	$	968.2		$	1,380.6		$	(60.2	)	$	110.4		$	2,400.0
Comprehensive income (loss)
Net income	—		—			306.5			—			13.9			320.4
Other comprehensive
income (loss), net of tax	—		—			—			24.7			2.1			26.8
Comprehensive income (loss)	—		—			306.5			24.7			16.0			347.2
Dividends declared on
common stock	—		—			(110.3		)	—			—			(110.3		)
Issuance of common stock	—		11.0			—			—			—			11.0
Stock-based compensation	—		1.5			—			—			—			1.5
Contributions from
noncontrolling interest
partners	—		29.1			—			—			44.4			73.5
Distributions to noncontrolling
interest partners	—		—			—			—			(12.8		)	(12.8		)
Deferred income taxes
attributable to contributions
from noncontrolling interest
partners	—		(11.2		)	—			—			—			(11.2		)
Balance at September 30, 2011	$	1.0	$	998.6		$	1,576.8		$	(35.5	)	$	158.0		$	2,698.9

Balance at December 31, 2009	$	1.0	$	886.7		$	1,227.8		$	(74.7	)	$	20.0		$	2,060.8
Comprehensive income (loss)
Net income	—		—			264.6			—			2.0			266.6
Other comprehensive
income (loss), net of tax	—		—			—			5.8			—			5.8
Comprehensive income (loss)	—		—			264.6			5.8			2.0			272.4
Dividends declared on
common stock	—		—			(105.9		)	—			—			(105.9		)
Issuance of common stock	—		13.5			—			—			—			13.5
Stock-based compensation	—		7.5			—			—			—			7.5
Balance at September 30, 2010	$	1.0	$	907.7		$	1,386.5		$	(68.9	)	$	22.0		$	2,248.3

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

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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 four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. All significant intercompany transactions have been eliminated in consolidation.

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.

Enogex is a provider of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting, storing and marketing natural gas. Most of Enogex's natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex's operations are organized into three business segments: (i) natural gas transportation and storage, (ii) natural gas gathering and processing and (iii) natural gas marketing. At September 30, 2011, the Company indirectly owns an 86.7 percent membership interest in Enogex Holdings, which in turn owns all of the membership interests in Enogex LLC, a Delaware single-member limited liability company (see Note 3). The Company continues to consolidate Enogex Holdings in its consolidated financial statements as OGE Energy has a controlling financial interest over the operations of Enogex Holdings. Prior to November 1, 2010, OER, whose primary operations are in natural gas marketing, was directly owned by OGE Energy. On November 1, 2010, OGE Energy distributed the equity interests in OER to Enogex LLC. Accordingly, the discussion that follows includes the results of OER in Enogex's results for all periods presented. Also, Enogex LLC holds a 50 percent ownership interest in Atoka. The Company has consolidated Atoka in its consolidated financial statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka.

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, 2011 and December 31, 2010, the results of its operations for the three and nine months ended September 30, 2011 and 2010 and the results of its cash flows for the nine months ended September 30, 2011 and 2010, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011 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 2010 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

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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:



	September 30,		December 31,
(In millions)	2011		2010
Regulatory Assets
Current
Fuel clause under recoveries	$	33.2	$	1.0
Other (A)	8.7		4.9
Total Current Regulatory Assets	$	41.9	$	5.9
Non-Current
Benefit obligations regulatory asset	$	274.0	$	365.5
Income taxes recoverable from customers, net	51.8		43.3
Smart Grid	29.4		14.2
Deferred storm expenses	25.5		28.6
Unamortized loss on reacquired debt	14.5		15.3
Deferred Pension expenses	10.2		13.5
Red Rock deferred expenses	6.9		7.2
Other	3.0		1.8
Total Non-Current Regulatory Assets	$	415.3	$	489.4
Regulatory Liabilities
Current
Smart Grid rider over collections (B)	$	23.5	$	10.4
Fuel clause over recoveries	8.5		29.9
Other (B)	15.7		10.5
Total Current Regulatory Liabilities	$	47.7	$	50.8
Non-Current
Accrued removal obligations, net	$	204.5	$	184.9
Pension tracker	18.7		8.2
Total Non-Current Regulatory Liabilities	$	223.2	$	193.1


(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 the Company 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, of which the financial effects could be significant.


2.	Accounting Pronouncement

In September 2011, the Financial Accounting Standards Board issued "Intangibles - Goodwill and Other: Testing Goodwill for Impairment" which amends previous guidance in this area. The new standard provides an entity the option of first assessing qualitative factors (events and circumstances) to determine whether it is necessary to perform the current two-step impairment test. If an entity determines, as a result of its qualitative assessment, that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. An entity can choose to perform the qualitative assessment on none, some or all of its reporting units. Under the new standard, an entity can bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step impairment test, and then resume performing the qualitative assessment in any subsequent period. The new standard also will expand upon the examples of events and circumstances that an entity should consider between annual impairment tests in determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The new standard is applicable to all entities that have goodwill reported in their financial statements. The new standard is effective for interim and annual reporting period goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The

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Company plans to adopt this new standard effective January 1, 2012. The Company expects to record a significant amount of goodwill as part of the gas gathering acquisitions discussed in Note 17.


3.	Noncontrolling Interest Owner

The following table summarizes changes in OGE Energy's equity attributable to changes in its ownership interest in Enogex Holdings during the nine months ended September 30, 2011. There were no contributions by OGE Energy or the ArcLight group to fund Enogex LLC's 2011 capital requirements during the three months ended September 30, 2011. Also, there were no sales of additional membership interests in Enogex Holdings to the ArcLight group during the three months ended September 30, 2011.



(In millions)
Net income attributable to OGE Energy	$	306.5
Transfers (to) from the noncontrolling interest
Increase in paid-in capital for sale of 100,000 units of Enogex Holdings	0.9
Increase in paid-in capital for issuance of 4,303,007 units of Enogex Holdings	28.2
Decrease in paid-in capital for deferred income taxes attributable to the sale and issuance of units
of Enogex Holdings	(11.2		)
Net transfers from the noncontrolling interest	17.9
Change from net income attributable to OGE Energy and transfers from noncontrolling interest	$	324.4

The following table summarizes changes in OGE Holdings' and the ArcLight group's membership interest in Enogex Holdings for the nine months ended September 30, 2011. Prior to November 1, 2010, Enogex Holdings was wholly owned by OGE Energy.



(In millions)	OGE Holdings		ArcLight group		Total
Balance at December 31, 2010 (units)	90.1		9.9		100.0
Ownership percentage at December 31, 2010	90.1	%	9.9	%	100.0	%

Sale of 100,000 units of Enogex Holdings (A)	(0.1	)	0.1		—
Issuance of 4,303,007 units of Enogex Holdings (B)	0.4		3.9		4.3

Balance at September 30, 2011 (units)	90.4		13.9		104.3
Ownership percentage at September 30, 2011	86.7	%	13.3	%	100.0	%

Issuance of 5,405,406 units of Enogex Holdings (C)	0.5		4.9		5.4
Issuance of 5,725,190 units of Enogex Holdings (D)	2.9		2.8		5.7

Balance at November 1, 2011 (units)	93.8		21.6		115.4
Ownership percentage at November 1, 2011	81.3	%	18.7	%	100.0	%

(A) On February 1, 2011, OGE Energy sold a 0.1 percent membership interest in Enogex Holdings to the ArcLight group for $1.9 million.

(B) On February 1, 2011, OGE Energy and the ArcLight group made contributions of $8.0 million and $71.6 million, respectively, to fund a portion of Enogex LLC's 2011 capital requirements.

(C) On October 3, 2011, OGE Energy and the ArcLight group made contributions of $10.0 million and $90.0 million, respectively, to fund a portion of Enogex LLC's 2011 capital requirements.

(D) On November 1, 2011, OGE Energy and the ArcLight group made contributions of $53.0 million each to fund Enogex's gas gathering acquisitions as discussed in Note 17.

The following table summarizes the quarterly distributions by Enogex Holdings to its partners during the nine months ended September 30, 2011.



	OGE Holdings		ArcLight group's
(In millions)	Portion		Portion		Total Distribution
First quarter 2011	$	7.5	$	0.8	$	8.3
Second quarter 2011	34.3		5.3		39.6
Third quarter 2011	43.4		6.6		50.0
Total	$	85.2	$	12.7	$	97.9

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4.	Impairment of Assets

Atoka operates a 20 MMcf/d refrigeration processing plant which processes gas gathered in the Atoka area. The processing plant is leased on a month-to-month basis. In August 2011, management made a decision to use third-party processing exclusively for gathered volumes dedicated to the Atoka plant and, therefore, to take the processing plant out of service and return it to the lessor in accordance with the rental agreement. As a result, in August 2011 Enogex recorded a pre-tax impairment loss of $5.0 million in the Gathering and Processing segment associated with the cost it had capitalized in connection with the installation of the leased plant as it will not be able to recover the remaining value of the assets through future cash flows. The Atoka plant assets were measured at fair value on a nonrecurring basis and are considered level 3 in the fair value hierarchy (see Note 5). The noncontrolling interest portion of the pre-tax impairment loss is $2.5 million which is included in Net Income Attributable to Noncontrolling Interests in the Company's Condensed Consolidated Statement of Income.


5.	Fair Value Measurements

The classification of the Company's fair value measurements requires judgment regarding the degree to which market data are 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 option 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). Instruments classified as Level 3 include NGLs options and the revaluation of the Atoka plant assets (see Note 4).

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, NGLs options contracts are valued using internally developed methodologies that consider historical relationships among various commodities 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

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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 following tables summarize the Company's assets and liabilities that are measured at fair value on a recurring basis at September 30, 2011 and December 31, 2010 as well as reconcile the Company's commodity contracts fair value to PRM Assets and Liabilities on the Company's Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010.



September 30, 2011
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	35.1		$	31.3		$	—	$	—
Significant other observable inputs (Level 2)	2.8			9.4			2.6		2.6
Significant unobservable inputs (Level 3)	1.5			—			—		—
Total fair value	39.4			40.7			2.6		2.6
Netting adjustments	(37.3		)	(33.7		)	—		—
Total	$	2.1		$	7.0		$	2.6	$	2.6

December 31, 2010
(In millions)	Commodity Contracts						Gas Imbalances (A)
	Assets			Liabilities			Assets		Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)	$	20.6		$	20.2		$	—	$	—
Significant other observable inputs (Level 2)	2.7			30.7			2.5		2.8
Significant unobservable inputs (Level 3)	13.3			—			—		—
Total fair value	36.6			50.9			2.5		2.8
Netting adjustments	(34.4		)	(34.1		)	—		—
Total	$	2.2		$	16.8		$	2.5	$	2.8


(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 liabilities exclude fuel reserves for over retained fuel due to shippers of $3.0 million and $3.9 million at September 30, 2011 and December 31, 2010, respectively, 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 Company's assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).



	Commodity Contracts
	Assets						Liabilities
(In millions)	2011			2010			2011		2010
Balance at January 1	$	13.3		$	49.0		$	—	$	14.7
Total gains or losses
Included in other comprehensive income	(4.8		)	(3.9		)	—		(5.1		)
Settlements	(3.3		)	(4.1		)	—		(1.4		)
Balance at March 31	5.2			41.0			—		8.2
Total gains or losses
Included in other comprehensive income	(1.0		)	7.2			—		(3.7		)
Settlements	(1.7		)	(6.1		)	—		(2.7		)
Balance at June 30	2.5			42.1			—		1.8
Total gains or losses
Included in other comprehensive income	0.4			(8.5		)	—		2.3
Settlements	(1.4		)	(6.7		)	—		(0.9		)
Balance at September 30	$	1.5		$	26.9		$	—	$	3.2

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The following table summarizes the fair value and carrying amount of the Company's financial instruments, including derivative contracts related to the Company's PRM activities, at September 30, 2011 and December 31, 2010.



	September 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
(In millions)	Amount		Value		Amount		Value
Price Risk Management Assets
Energy Derivative Contracts	$	2.1	$	2.1	$	2.2	$	2.2
Price Risk Management Liabilities
Energy Derivative Contracts	$	7.0	$	7.0	$	16.8	$	16.8
Long-Term Debt
OG&E Senior Notes	$	1,903.8	$	2,362.8	$	1,655.0	$	1,831.5
OGE Energy Senior Notes	99.6		109.7		99.7		106.4
OG&E Industrial Authority Bonds	135.4		135.4		135.4		135.4
Enogex LLC Senior Notes	448.1		502.7		447.8		480.7
Enogex LLC Revolving Credit Agreement	—		—		25.0		25.0

The carrying value of the financial instruments on the Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company's energy derivative contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties. 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.


6.	Derivative Instruments and Hedging Activities

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

Commodity Price Risk

The Company primarily uses forward physical contracts, commodity price swap contracts and commodity price option features to manage the Company's commodity price risk exposures. Commodity derivative instruments used by the Company are as follows:


•	NGLs put options and NGLs swaps are used to manage Enogex's NGLs exposure associated with its processing agreements;


•	natural gas swaps are used to manage Enogex's keep-whole natural gas exposure associated with its processing operations and Enogex's natural gas exposure associated with operating its gathering, transportation and storage assets;


•	natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OER's natural gas exposure associated with its storage and transportation contracts; and


•	natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OER's marketing and trading activities.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by its operations, (ii) commodity contracts for the sale of NGLs produced by Enogex's gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

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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 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 designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex's 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, pipeline and storage operations (operational gas hedges). The Company also designates as cash flow hedges certain derivatives used to manage natural gas commodity exposure for certain natural gas storage inventory positions. Enogex's cash flow hedges at September 30, 2011 mature by the end of the first quarter of 2012.

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, 2011 and December 31, 2010, 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 OER's asset management, marketing and trading activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

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Quantitative Disclosures Related to Derivative Instruments

At September 30, 2011, the Company had the following derivative instruments that were designated as cash flow hedges.



	2011 Gross Notional
(In millions)	Volume (A)
Enogex processing hedges
NGLs sales	0.3
Natural gas purchases	1.3
Enogex marketing hedges
Natural gas sales	1.9


(A)	Natural gas in million British thermal units; NGLs in barrels.

At September 30, 2011, the Company had the following derivative instruments that were not designated as hedging instruments.



(In millions)	Gross Notional Volume (A)
	Purchases	Sales
Natural gas (B)
Physical (C)(D)	16.5	58.0
Fixed Swaps/Futures	48.6	47.3
Options	19.2	13.0
Basis Swaps	7.7	8.1


(A)	Natural gas in million British thermal units.


(B)	85.5 percent of the natural gas contracts have durations of one year or less, 6.5 percent have durations of more than one year and less than two years and 8.0 percent have durations of more than two years.


(C)	Of the natural gas physical purchases and sales volumes not designated as hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.


(D)	Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via Enogex's processing contracts, which are not derivative instruments and are excluded from the table above.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at September 30, 2011 are as follows:



		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	1.5	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		8.0
	Other Current Assets	1.9		0.2
Total		$	3.4	$	8.2

Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	0.1	$	0.1
	Other Current Assets	33.5		31.7
Physical Purchases/Sales	Current PRM	1.8		0.4
	Non-Current PRM	0.3		0.1
Financial Options	Other Current Assets	0.3		0.2
Total		$	36.0	$	32.5
Total Gross Derivatives (A)		$	39.4	$	40.7


(A)	See Note 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at September 30, 2011.

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The fair value of the derivative instruments that are presented in the Company's Condensed Consolidated Balance Sheet at December 31, 2010 are as follows:



		Fair Value
	Balance Sheet
Instrument	Location	Assets		Liabilities
		(In millions)
Derivatives Designated as Hedging Instruments
NGLs
Financial Options	Current PRM	$	13.3	$	—
Natural Gas
Financial Futures/Swaps	Current PRM	—		28.8
	Other Current Assets	0.6		0.3
Total		$	13.9	$	29.1

Derivatives Not Designated as Hedging Instruments
Natural Gas
Financial Futures/Swaps	Current PRM	$	—	$	0.1
	Other Current Assets	20.0		19.8
Physical Purchases/Sales	Current PRM	1.4		1.2
	Non-Current PRM	0.8		—
Financial Options	Other Current Assets	0.5		0.7
Total		$	22.7	$	21.8
Total Gross Derivatives (A)		$	36.6	$	50.9


(A)	See Note 5 for a reconciliation of the Company's total derivatives fair value to the Company's Condensed Consolidated Balance Sheet at December 31, 2010.

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, 2011.

Derivatives in Cash Flow Hedging Relationships



			Amount Reclassified
	Amount Recognized		from Accumulated Other			Amount
	in Other		Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)		into Income			Income
NGLs Financial Options	$	0.2	$	(2.6	)	$	—
Natural Gas Financial Futures/Swaps	0.2		(7.5		)	—
Total	$	0.4	$	(10.1	)	$	—


(A)	The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at September 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $8.4 million.

Derivatives Not Designated as Hedging Instruments



	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(2.2	)
Natural Gas Financial Futures/Swaps	0.2
Total	$	(2.0	)

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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, 2010.

Derivatives in Cash Flow Hedging Relationships



				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income			into Income			Income
NGLs Financial Options	$	(12.2	)	$	1.5		$	—
NGLs Financial Futures/Swaps	(1.2		)	(0.3		)	—
Natural Gas Financial Futures/Swaps	(5.5		)	(6.7		)	—
Total	$	(18.9	)	$	(5.5	)	$	—

Derivatives Not Designated as Hedging Instruments



	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(2.3	)
Natural Gas Financial Futures/Swaps	0.6
Total	$	(1.7	)

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, 2011.

Derivatives in Cash Flow Hedging Relationships



				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income (A)			into Income			Income
NGLs Financial Options	$	(9.0	)	$	(8.3	)	$	—
Natural Gas Financial Futures/Swaps	—			(22.2		)	—
Total	$	(9.0	)	$	(30.5	)	$	—


(A)	The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at September 30, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $8.4 million.

Derivatives Not Designated as Hedging Instruments



	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(7.1	)
Natural Gas Financial Futures/Swaps	(0.2		)
Total	$	(7.3	)

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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, 2010.

Derivatives in Cash Flow Hedging Relationships



				Amount Reclassified
	Amount Recognized			from Accumulated Other			Amount
	in Other			Comprehensive Income			Recognized in
(In millions)	Comprehensive Income			into Income			Income
NGLs Financial Options	$	(1.2	)	$	2.0		$	—
NGLs Financial Futures/Swaps	2.1			(2.2		)	—
Natural Gas Financial Futures/Swaps	(15.4		)	(18.7		)	0.1
Total	$	(14.5	)	$	(18.9	)	$	0.1

Derivatives Not Designated as Hedging Instruments



	Amount
	Recognized in
(In millions)	Income
Natural Gas Physical Purchases/Sales	$	(6.4	)
Natural Gas Financial Futures/Swaps	0.8
Total	$	(5.6	)

For derivatives designated as cash flow hedges in the tables above, amounts reclassified from Accumulated Other Comprehensive Income into income (effective portion) and amounts recognized in income (ineffective portion) for the three and nine months ended September 30, 2011 and 2010, 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, 2011 and 2010, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody's Investors Services or Standard & Poor's Ratings Services were to lower the Company's senior unsecured debt rating to a below investment grade rating, at September 30, 2011, the Company would have been required to post $6.1 million of cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position at September 30, 2011. In addition, the Company could be required to provide additional credit assurances in future dealings with third parties, which could include letters of credit or cash collateral.


7.	Stock-Based Compensation

The following table summarizes the Company's pre-tax compensation expense and related income tax benefit for the three and nine months ended September 30, 2011 and 2010 related to the Company's performance units and restricted stock.



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2011		2010		2011		2010
Performance units
Total shareholder return	$	1.9	$	1.5	$	5.6	$	4.7
Earnings per share	0.8		1.0		3.7		1.8
Total performance units	2.7		2.5		9.3		6.5
Restricted stock	0.2		0.3		0.7		0.7
Total compensation expense	$	2.9	$	2.8	$	10.0	$	7.2
Income tax benefit	$	1.1	$	1.1	$	3.9	$	2.8

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The following table summarizes the activity of the Company's stock-based compensation during the three months ended September 30, 2011.



	Shares	Fair Value
Grants
Restricted stock	14,218	$49.24

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, 2011, there were 14,718 shares and 284,423 shares, respectively, of new common stock issued pursuant to the Company's stock incentive plans related to exercised stock options, restricted stock grants and payouts of earned performance units. During the three and nine months ended September 30, 2011, there were 1,150 shares and 3,810 shares, respectively, of restricted stock returned to the Company to satisfy tax liabilities. The Company received less than $0.1 million and $0.8 million, respectively, during the three and nine months ended September 30, 2011 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, 2011 due to the Company being in a tax net operating loss position in 2011.


8.	Accumulated Other Comprehensive Income (Loss)

The following table summarizes the components of accumulated other comprehensive loss at September 30, 2011 and December 31, 2010 attributable to OGE Energy. At both September 30, 2011 and December 31, 2010, there was no accumulated other comprehensive loss related to Enogex's noncontrolling interest in Atoka.



	September 30,			December 31,
(In millions)	2011			2010
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	(29.4	)	$	(31.1	)
Prior service cost	(0.2		)	(0.5		)
Postretirement plans:
Net loss	(12.3		)	(13.6		)
Prior service cost	9.3			—
Net transition obligation	(0.2		)	(0.3		)
Deferred commodity contracts hedging losses	(5.6		)	(19.5		)
Deferred interest rate swaps hedging losses	(0.8		)	(1.0		)
Total accumulated other comprehensive loss	(39.2		)	(66.0		)
Less: Accumulated other comprehensive loss attributable to noncontrolling interests	(3.7		)	(5.8		)
Accumulated other comprehensive loss, net of tax	$	(35.5	)	$	(60.2	)


9.	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 2007 or state and local tax examinations by tax authorities for years prior to 2002. 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. The Company 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 the production from its wind farms. In addition, OG&E and Enogex earn Oklahoma state tax credits associated with their investments in electric generating and natural gas processing facilities which further reduce the Company's effective tax rate.


10.	Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

The Company issued 69,986 shares and 215,832 shares, respectively, of common stock under its Automatic Dividend Reinvestment and Stock Purchase Plan during the three and nine months ended September 30, 2011 and received proceeds of $3.4 million and $10.6 million, respectively, during the three and nine months ended September 30, 2011. The Company may, from time to time, issue additional shares under its Automatic Dividend Reinvestment and Stock Purchase Plan to fund capital

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requirements or working capital needs. At September 30, 2011, there were