Edgar Filing: OGE ENERGY CORP.

oge1stqtr11.htm

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 March 31, 2011

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. Yes þ No o

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).

Yes o No þ

At March 31, 2011, there were 97,909,150 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 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 Cash Flows		3
Condensed Consolidated Balance Sheets		4
Condensed Consolidated Statements of Changes in Stockholders’ Equity		6
Condensed Consolidated Statements of Comprehensive Income		7
Notes to Condensed Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25

Item 3. Quantitative and Qualitative Disclosures About Market Risk		38

Item 4. Controls and Procedures		39


Part II – OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 1A. Risk Factors		40

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		40

Item 6. Exhibits		40

Signature		41

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
AEFUDC	Allowance for equity funds used during construction
APSC	Arkansas Public Service Commission
ArcLight affiliate	Bronco Midstream Holdings, LLC, Bronco Midstream Holdings II, LLC, collectively
ArcLight group	ArcLight Energy Partners Fund IV, L.P. and affiliates
Atoka	Atoka Midstream LLC joint venture
BART	Best Available Retrofit Technology
Company	OGE Energy, collectively with its subsidiaries
Crossroads	OG&E’s Crossroads wind project in Dewey County, Oklahoma
DRIP/DSPP	Automatic Dividend Reinvestment and Stock Purchase Plan
Dry Scrubbers	Dry flue gas desulfurization units with Spray Dryer Absorber
EHV	Extra High Voltage
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 Energy
Enogex Holdings LLC Agreement	Amended and Restated Limited Liability Agreement of Enogex Holdings
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States
GFB	Guaranteed Flat Bill
GCELC	Gulf Coast Environmental Labor Coalition
kV	Kilovolt
MEP	Midcontinent Express Pipeline, LLC
MMBtu	Million British thermal unit
MMcf/d	Million cubic feet per day
Moody’s	Moody’s Investors Services
MW	Megawatt
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
Pension Plan	Qualified defined benefit retirement plan
POL	Percent-of-liquids
PRM	Price risk management
SEC	Securities and Exchange Commission
SIP	State implementation plan
SO2	Sulfur dioxide
SOC	Statement of Operating Conditions
SPP	Southwest Power Pool
Standard & Poor’s	Standard & Poor’s Ratings Services
System sales	Sales to OG&E’s customers
TBtu/d	Trillion British thermal units per day
VaR	Value-at-risk
Windspeed	OG&E’s transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma

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 POL, 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 SEC 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.


OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended
	March 31,
(In millions, except per share data)	2011		2010
OPERATING REVENUES
Electric Utility operating revenues	$	422.1	$	444.0
Natural Gas Midstream Operations operating revenues		418.4		431.8
Total operating revenues		840.5		875.8
COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)
Electric Utility cost of goods sold		207.5		238.9
Natural Gas Midstream Operations cost of goods sold		325.7		331.2
Total cost of goods sold		533.2		570.1
Gross margin on revenues		307.3		305.7
OPERATING EXPENSES
Other operation and maintenance		138.3		123.6
Depreciation and amortization		74.0		70.3
Taxes other than income		27.1		25.0
Total operating expenses		239.4		218.9
OPERATING INCOME		67.9		86.8
OTHER INCOME (EXPENSE)
Interest income		0.1		---
Allowance for equity funds used during construction		4.4		2.3
Other income		6.3		3.1
Other expense		(2.3)		(2.4)
Net other income		8.5		3.0
INTEREST EXPENSE
Interest on long-term debt		35.4		33.6
Allowance for borrowed funds used during construction		(2.3)		(1.2)
Interest on short-term debt and other interest charges		1.0		1.7
Interest expense		34.1		34.1
INCOME BEFORE TAXES		42.3		55.7
INCOME TAX EXPENSE		12.6		30.5
NET INCOME		29.7		25.2
Less: Net income attributable to noncontrolling interests		4.9		1.0
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	24.8	$	24.2
BASIC AVERAGE COMMON SHARES OUTSTANDING		97.7		97.1
DILUTED AVERAGE COMMON SHARES OUTSTANDING		99.1		98.5
BASIC EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.25	$	0.25
DILUTED EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.25	$	0.25
DIVIDENDS DECLARED PER COMMON SHARE	$	0.3750	$	0.3625

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

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended
	March 31,
(In millions)	2011		2010

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	29.7	$	25.2
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation and amortization		74.0		70.3
Deferred income taxes and investment tax credits, net		12.6		15.6
Allowance for equity funds used during construction		(4.4)		(2.3)
Stock-based compensation expense		(2.3)		0.4
Price risk management assets		0.7		0.7
Price risk management liabilities		3.2		3.1
Regulatory assets		6.0		4.2
Regulatory liabilities		2.8		(2.2)
Other assets		2.0		1.1
Other liabilities		1.3		2.7
Change in certain current assets and liabilities
Accounts receivable, net		8.1		29.3
Accrued unbilled revenues		6.3		10.9
Income taxes receivable		---		81.7
Fuel, materials and supplies inventories		16.1		(14.1)
Gas imbalance assets		(2.1)		(1.2)
Fuel clause under recoveries		0.6		(0.6)
Other current assets		6.2		1.8
Accounts payable		(43.1)		(30.4)
Gas imbalance liabilities		1.4		0.1
Fuel clause over recoveries		(4.5)		(30.5)
Other current liabilities		(38.3)		(49.8)
Net Cash Provided from Operating Activities		76.3		116.0
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(195.0)		(135.0)
Reimbursement of capital expenditures		11.3		3.3
Other investing activities		1.7		1.1
Net Cash Used in Investing Activities		(182.0)		(130.6)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term debt		92.2		166.6
Contributions from noncontrolling interest partners		73.5		---
Issuance of common stock		4.1		4.9
Proceeds from line of credit		---		115.0
Retirement of long-term debt		---		(289.2)
Distributions to noncontrolling interest partners		(0.8)		---
Repayment of line of credit		(25.0)		---
Dividends paid on common stock		(36.6)		(35.1)
Net Cash Provided from (Used in) Financing Activities		107.4		(37.8)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1.7		(52.4)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2.3		58.1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4.0	$	5.7

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

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,		December 31,
	2011		2010
(In millions)	(Unaudited)

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4.0	$	2.3
Accounts receivable, less reserve of $1.4 and $1.9, respectively		269.8		277.9
Accrued unbilled revenues		50.5		56.8
Income taxes receivable		4.7		4.7
Fuel inventories		139.6		158.8
Materials and supplies, at average cost		86.4		83.3
Price risk management		0.8		1.4
Gas imbalances		4.6		2.5
Deferred income taxes		17.1		18.7
Fuel clause under recoveries		0.4		1.0
Other		18.5		24.7
Total current assets		596.4		632.1

OTHER PROPERTY AND INVESTMENTS, at cost		45.9		44.9

PROPERTY, PLANT AND EQUIPMENT
In service		9,280.4		9,188.0
Construction work in progress		550.7		460.0
Total property, plant and equipment		9,831.1		9,648.0
Less accumulated depreciation		3,231.5		3,183.6
Net property, plant and equipment		6,599.6		6,464.4

DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets		412.1		489.4
Price risk management		0.7		0.8
Other		35.9		37.5
Total deferred charges and other assets		448.7		527.7

TOTAL ASSETS	$	7,690.6	$	7,669.1

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

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)

	March 31,		December 31,
	2011		2010
(In millions)	(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	237.2	$	145.0
Accounts payable		294.5		321.7
Dividends payable		36.7		36.6
Customer deposits		68.7		67.0
Accrued taxes		23.8		39.3
Accrued interest		30.5		53.1
Accrued compensation		35.3		43.3
Price risk management		17.1		16.8
Gas imbalances		8.1		6.7
Fuel clause over recoveries		25.4		29.9
Other		61.2		55.1
Total current liabilities		838.5		814.5

LONG-TERM DEBT		2,338.1		2,362.9

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		285.0		372.4
Deferred income taxes		1,463.5		1,434.8
Deferred investment tax credits		8.5		9.4
Regulatory liabilities		205.6		193.1
Price risk management		0.1		---
Deferred revenues		36.4		36.7
Other		46.0		45.3
Total deferred credits and other liabilities		2,045.1		2,091.7

Total liabilities		5,221.7		5,269.1

COMMITMENTS AND CONTINGENCIES (NOTE 13)

STOCKHOLDERS’ EQUITY
Common stockholders’ equity		988.8		969.2
Retained earnings		1,368.7		1,380.6
Accumulated other comprehensive loss, net of tax		(46.9)		(60.2)
Total OGE Energy stockholders’ equity		2,310.6		2,289.6
Noncontrolling interests		158.3		110.4
Total stockholders’ equity		2,468.9		2,400.0

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,690.6	$	7,669.1

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)

		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	---	---	24.8	---	4.9	29.7
Other comprehensive income (loss), net of tax	---	---	---	13.3	(0.6)	12.7
Comprehensive income	---	---	24.8	13.3	4.3	42.4
Dividends declared on common stock	---	---	(36.7)	---	---	(36.7)
Issuance of common stock	---	4.1	---	---	---	4.1
Stock-based compensation	---	(2.4)	---	---	---	(2.4)
Contributions from noncontrolling interest partners	---	29.1	---	---	44.4	73.5
Distributions to noncontrolling interest partners	---	---	---	---	(0.8)	(0.8)
Deferred income taxes attributable to contributions from noncontrolling interest partners	---	(11.2)	---	---	---	(11.2)
Balance at March 31, 2011	$ 1.0	$ 987.8	$ 1,368.7	$ (46.9)	$ 158.3	$ 2,468.9

Balance at December 31, 2009	$ 1.0	$ 886.7	$ 1,227.8	$ (74.7)	$ 20.0	$ 2,060.8
Comprehensive income (loss)
Net income	---	---	24.2	---	1.0	25.2
Other comprehensive loss, net of tax	---	---	---	(1.5)	---	(1.5)
Comprehensive income (loss)	---	---	24.2	(1.5)	1.0	23.7
Dividends declared on common stock	---	---	(35.3)	---	---	(35.3)
Issuance of common stock	---	4.9	---	---	---	4.9
Stock-based compensation	---	1.6	---	---	---	1.6
Balance at March 31, 2010	$ 1.0	$ 893.2	$ 1,216.7	$ (76.2)	$ 21.0	$ 2,055.7

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
	March 31,
(In millions)	2011		2010
Net income	$	29.7	$	25.2
Other comprehensive income (loss), net of tax
Pension Plan and Restoration of Retirement Income Plan:
Amortization of deferred net loss, net of tax of $0.4 million and $0.7 million, respectively		0.5		0.5
Amortization of prior service cost, net of tax of ($0.1) million and $0, respectively		0.2		---
Postretirement plans:
Amortization of deferred net loss, net of tax of $0.5 million and $0.4 million, respectively		0.2		0.6
Amortization of deferred net transition obligation, net of tax of ($0.1) million and $0, respectively		0.1		0.2
Amortization of prior service cost, net of tax of $5.9 million and $0, respectively		10.1		(0.2)
Deferred commodity contracts hedging gains (losses), net of tax of $1.2 million and ($1.6) million, respectively		1.5		(2.7)
Deferred interest rate swaps hedging gains, net of tax of $0.1 million and $0, respectively		0.1		0.1
Other comprehensive income (loss), net of tax		12.7		(1.5)
Total comprehensive income		42.4		23.7
Less: Comprehensive income attributable to noncontrolling interest for sale of equity investment		(1.7)		---
Less: Comprehensive income attributable to noncontrolling interests		6.0		1.0
Total comprehensive income attributable to OGE Energy	$	38.1	$	22.7

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 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. Through OGE Holdings, 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 2). The Company continues to consolidate 100 percent of 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 100 percent of 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 SEC. 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 March 31, 2011 and December 31, 2010, the results of its operations for the three months ended March 31, 2011 and 2010 and the results of its cash flows for the three months ended March 31, 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 months ended March 31, 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 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:

	March 31,		December 31,
(In millions)	2011		2010
Regulatory Assets
Current
Fuel clause under recoveries	$	0.4	$	1.0
Other (A)		6.5		4.9
Total Current Regulatory Assets	$	6.9	$	5.9

Non-Current
Benefit obligations regulatory asset	$	285.4	$	365.5
Income taxes recoverable from customers, net		45.6		43.3
Deferred storm expenses		27.0		28.6
Smart Grid		18.3		14.2
Unamortized loss on reacquired debt		15.1		15.3
Deferred Pension Plan expenses		12.4		13.5
Red Rock deferred expenses		7.1		7.2
Other		1.2		1.8
Total Non-Current Regulatory Assets	$	412.1	$	489.4

Regulatory Liabilities
Current
Fuel clause over recoveries	$	25.4	$	29.9
Other (B)		27.2		20.9
Total Current Regulatory Liabilities	$	52.6	$	50.8

Non-Current
Accrued removal obligations, net	$	192.3	$	184.9
Deferred Pension Plan expenses		10.7		8.2
Other		2.6		---
Total Non-Current Regulatory Liabilities	$	205.6	$	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; the financial effects of which could be significant.

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Consolidated Statement of Income and Condensed Consolidated Statement of Cash Flows to conform to the 2011 presentation primarily related to the presentation of regulatory assets and liabilities.

2. ArcLight Transaction

As previously reported in the Company’s 2010 Form 10-K, in February 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. Also, on February 1, 2011, OGE Energy sold a 0.1 percent membership interest in Enogex Holdings to the ArcLight affiliate for $1.9 million. As a result of these transactions, the ArcLight group has a 13.3 percent membership interest in Enogex Holdings at March 31, 2011. The following table summarizes changes in OGE Energy’s equity attributable to changes in its ownership interest in Enogex Holdings during the three months ended March 31, 2011.

(In millions)
Net income attributable to OGE Energy	$	24.8
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	$	42.7

Pursuant to the Enogex Holdings LLC Agreement, on March 1, 2011, Enogex Holdings made a quarterly distribution of $8.3 million, of which $7.5 million was OGE Holdings’ portion.

3. 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.

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 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 following tables summarize the Company’s assets and liabilities that are measured at fair value on a recurring basis at March 31, 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 March 31, 2011 and December 31, 2010.

March 31, 2011
(In millions)		Commodity Contracts		Gas Imbalances (A)
		Assets	Liabilities	Assets	Liabilities (B)
Quoted market prices in active market for identical assets (Level 1)		$ 14.6	$ 14.0	$ ---	$ ---
Significant other observable inputs (Level 2)		2.1	22.8	4.6	5.6
Significant unobservable inputs (Level 3)		5.2	---	---	---
Total fair value		21.9	36.8	4.6	5.6
Netting adjustments		(20.4)	(19.6)	---	---
Total		$ 1.5	$ 17.2	$ 4.6	$ 5.6

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 $2.5 million and $3.9 million at March 31, 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
Amount of total gains or losses included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities held at March 31 (reported in Operating Revenues)	$	---	$	---	$	---	$	---

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 March 31, 2011 and December 31, 2010.

	March 31, 2011					December 31, 2010
	Carrying		Fair				Carrying	Fair
(In millions)	Amount		Value				Amount	Value
Price Risk Management Assets
Energy Derivative Contracts	$	1.5		$	1.5	$	2.2	$	2.2

Price Risk Management Liabilities
Energy Derivative Contracts	$	17.2		$	17.2	$	16.8	$	16.8

Long-Term Debt
OG&E Senior Notes	$	1,655.1		$	1,810.4	$	1,655.0	$	1,831.5
OGE Energy Senior Notes		99.7			105.7		99.7		106.4
OG&E Industrial Authority Bonds		135.4			135.4		135.4		135.4
Enogex LLC Senior Notes		447.9			483.4		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.

4. 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.

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. Maturities of Enogex’s cash flow hedging activity at March 31, 2011 occur during 2011.

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 March 31, 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.

Quantitative Disclosures Related to Derivative Instruments

At March 31, 2011, the Company had the following derivative instruments that were designated as cash flow hedges.

(In millions)		2011 Gross Notional Volume (A)
Enogex processing hedges
NGLs sales			1.0
Natural gas purchases			3.9
(A)	Natural gas in MMBtu; NGLs in barrels.

At March 31, 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)			18.0	51.3
Fixed Swaps/Futures			53.6	51.4
Options			5.5	9.8
Basis Swaps			10.2	7.8
(A)	Natural gas in MMBtu.
(B)	89.4 percent of the natural gas contracts have durations of one year or less, 7.3 percent have durations of more than one year and less than two years and 3.3 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 March 31, 2011 are as follows:

			Fair Value
		Balance Sheet
Instrument		Location		Assets		Liabilities
			(In millions)
Derivatives Designated as Hedging Instruments

NGLs
Financial Options		Current PRM	$	5.2	$		---
Natural Gas
Financial Futures/Swaps		Current PRM		---			21.3
Total			$	5.2	$		21.3

Derivatives Not Designated as Hedging Instruments

Natural Gas
Financial Futures/Swaps		Current PRM	$	0.3	$		0.3
		Other Current Assets		14.8			14.0
Physical Purchases/Sales		Current PRM		0.7			0.9
		Non-Current PRM		0.7			0.1
Financial Options		Other Current Assets		0.2			0.2
Total			$	16.7	$		15.5
Total Gross Derivatives (A)			$	21.9	$		36.8
(A)	See Note 3 for a reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at March 31, 2011.

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 3 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 table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended March 31, 2011.

Derivatives in Cash Flow Hedging Relationships

(In millions)		Amount Recognized in OCI (A)		Amount Reclassified from Accumulated OCI into Income		Amount Recognized in Income

NGLs Financial Options		$	(6.8)	$	(2.5)	$	---
Natural Gas Financial Futures/Swaps			(0.2)		(7.3)		---
Total		$	(7.0)	$	(9.8)	$	---
(A)	The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at March 31, 2011 that is expected to be reclassified into income within the next 12 months is a loss of $27.2 million.

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income

Natural Gas Physical Purchases/Sales	$	(2.1)
Natural Gas Financial Futures/Swaps		(0.2)
Total	$	(2.3)

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended March 31, 2010.

Derivatives in Cash Flow Hedging Relationships

(In millions)	Amount Recognized in OCI		Amount Reclassified from Accumulated OCI into Income		Amount Recognized in Income

NGLs Financial Options	$	0.5	$	(0.6)	$	---
NGLs Financial Futures/Swaps		1.3		(1.4)		---
Natural Gas Financial Futures/Swaps		(9.9)		(3.3)		0.1
Total	$	(8.1)	$	(5.3)	$	0.1

Derivatives Not Designated as Hedging Instruments

(In millions)	Amount Recognized in Income

Natural Gas Physical Purchases/Sales	$	(0.1)
Natural Gas Financial Futures/Swaps		0.7
Total	$	0.6

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 months ended March 31, 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 months ended March 31, 2011 and 2010, if any, are reported in Operating Revenues.

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s or Standard & Poor’s were to lower the Company’s senior unsecured debt rating to a below investment grade rating, at March 31, 2011, the Company would have been required to post $16.3 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 March 31, 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.

5. Stock-Based Compensation

The following table summarizes the Company’s pre-tax compensation expense and related income tax benefit for the three months ended March 31, 2011 and 2010 related to the Company’s performance units and restricted stock.

	Three Months Ended March 31,
(In millions)	2011		2010
Performance units
Total shareholder return	$	1.7	$	1.6
EPS		2.2		0.4
Total performance units		3.9		2.0
Restricted stock		0.2		0.1
Total compensation expense	$	4.1	$	2.1
Income tax benefit	$	1.5	$	0.8

The following table summarizes the activity of the Company’s stock-based compensation during the three months ended March 31, 2011.

		Units/Shares		Fair Value
Grants
Performance units (Total shareholder return)			213,721	$	46.09
Performance units (EPS)			71,238	$	41.61
Restricted stock			2,855	$	46.18
Conversions
Performance units (A)			218,425		N/A
(A)	Performance units were converted based on a payout ratio of 178.4 percent of the target number of performance units granted in February 2008 and are included in the 267,876 shares of new common stock issued during the three months ended March 31, 2011 as discussed below.

The Company issues new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During the three months ended March 31, 2011, there were 267,876 shares 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. The Company received $0.3 million during the three months ended March 31, 2011 related to exercised stock options and realized an income tax benefit for the tax deductions from the exercised stock options of $0.2 million.

6. Accumulated Other Comprehensive Income (Loss)

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

	March 31,			December 31,
(In millions)	2011			2010
Pension Plan and Restoration of Retirement Income Plan:
Net loss	$	(30.6	)	$	(31.1	)
Prior service cost		(0.3	)		(0.5	)
Postretirement plans:
Net loss		(13.4	)		(13.6	)
Prior service cost		10.1			---
Net transition obligation		(0.2	)		(0.3	)
Deferred commodity contracts hedging losses		(18.0	)		(19.5	)
Deferred interest rate swaps hedging losses		(0.9	)		(1.0	)
Total accumulated other comprehensive loss		(53.3	)		(66.0	)
Less: Other comprehensive loss attributable to noncontrolling interests		(6.4	)		(5.8	)
Total accumulated other comprehensive loss attributable to OGE Energy	$	(46.9	)	$	(60.2	)

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 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.

8. Common Equity

DRIP/DSPP

The Company issued 80,997 shares of common stock under its DRIP/DSPP during the three months ended March 31, 2011 and received proceeds of $3.8 million. The Company may, from time to time, issue additional shares under its DRIP/DSPP to fund capital requirements or working capital needs. At March 31, 2011, there were 2,565,291 shares of unissued common stock reserved for issuance under the Company’s DRIP/DSPP.

EPS

Outstanding shares for purposes of basic and diluted EPS were calculated as follows:

	Three Months Ended
	March 31,
(In millions)	2011		2010
Average Common Shares Outstanding
Basic average common shares outstanding		97.7		97.1
Effect of dilutive securities:
Contingently issuable shares (performance units)		1.4		1.4
Diluted average common shares outstanding		99.1		98.5
Anti-dilutive shares excluded from EPS calculation		---		---

9. Long-Term Debt

At March 31, 2011, the Company was in compliance with all of its debt agreements.

OG&E has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds at various dates prior to the maturity. 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)
0.39% - 0.44%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.38% - 0.44%	Muskogee Industrial Authority, January 1, 2025		32.4
0.50% - 0.50%	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.

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 $237.2 million and $145.0 million at March 31, 2011 and December 31, 2010, respectively. The following table provides information regarding the Company’s revolving credit agreements and available cash at March 31, 2011.

Revolving Credit Agreements and Available Cash
		Aggregate		Amount		Weighted-Average
Entity		Commitment		Outstanding (A)		Interest Rate		Maturity
		(In millions)
OGE Energy (B)		$	596.0	$	237.2	0.34	%(D)	December 6, 2012
OG&E (C)			389.0		0.3	0.32	%(D)	December 6, 2012
Enogex LLC (E)			250.0		---	---	%(D)	March 31, 2013
			1,235.0		237.5	0.34	%
Cash			4.0		N/A	N/A		N/A
Total		$	1,239.0	$	237.5	0.34	%
(A)	Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2011.
(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. At March 31, 2011, there was $237.2 million in outstanding commercial paper borrowings.
(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. At March 31, 2011, there was $0.3 million supporting letters of credit.
(D)	Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit.
(E)	This bank facility is available to provide revolving credit borrowings for Enogex LLC. As Enogex LLC’s credit agreement matures on March 31, 2013, along with its intent in utilizing its credit agreement, borrowings thereunder are classified as long-term debt in the Company’s Condensed Consolidated Balance Sheets.

On April 1, 2011, OG&E posted letters of credit with the SPP of $1.9 million related to OG&E’s portion of upgrade costs to the transmission system to allow the 150 MW CPV Keenan wind farm and the 130 MW Edison Mission Energy wind farm to operate at full capacity for OG&E’s system load.

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 of the Company 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.

Unlike OGE Energy and Enogex, 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, 2011 and ending December 31, 2012.

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				Three Months Ended
		March 31,				March 31,
(In millions)		2011		2010		2011		2010
Service cost		$	4.4	$	4.4	$	0.3	$	0.2
Interest cost			8.3		7.8		0.1		0.1
Expected return on plan assets			(11.4)		(10.7)		---		---
Amortization of net loss			4.8		5.1		0.1		0.1
Amortization of unrecognized prior service cost			0.6		0.6		0.2		0.1
Net periodic benefit cost (A)		$	6.7	$	7.2	$	0.7	$	0.5
(A)	In addition to the $7.4 million and $7.7 million of net periodic benefit cost recognized during the three months ended March 31, 2011 and 2010, respectively, the Company recognized an increase in pension expense during the three months ended March 31, 2011 and 2010 of $2.6 million and $1.9 million, respectively, to maintain the allowable

amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Deferred Pension Plan Expenses (see Note 1).

	Postretirement Benefit Plans
	Three Months Ended
	March 31,
(In millions)	2011		2010
Service cost	$	0.9	$	1.2
Interest cost		3.1		4.2
Expected return on plan assets		(1.3)		(1.7)
Amortization of transition obligation		0.7		0.7
Amortization of net loss		4.6		2.7
Amortization of unrecognized prior service cost		(4.1)		---
Net periodic benefit cost	$	3.9	$	7.1

Pension Plan Funding

The Company previously disclosed in its 2010 Form 10-K that it may contribute up to $50 million to its Pension Plan during 2011. In April 2011, the Company contributed $20 million to its Pension Plan and currently expects to contribute an additional $30 million during the remainder of 2011. Any remaining expected contributions to its Pension Plan during 2011 would be discretionary contributions, anticipated to be in the form of cash, and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

Postretirement Benefit Plan (Retiree Medical)

In January 2011, the Company adopted amendments to its retiree medical plan. Effective January 1, 2012, medical costs for pre-65 aged eligible retirees will be fixed at the 2011 level and the Company will cover future annual medical inflationary cost increases up to five percent. Increases in excess of five percent annually will be covered by the pre-65 aged retiree in the form of premium increases. Also, effective January 1, 2012, the Company will supplement Medicare coverage for Medicare-eligible retirees, providing them a fixed stipend based on the Company’s expected average 2011 premium for medical and drug coverage, and allow those Medicare-eligible retirees to acquire coverage from a Company-provided third-party administrator. The effect of these plan amendments is reflected in the Company’s March 31, 2011 Condensed Consolidated Balance Sheet as a reduction to the accumulated postretirement benefit obligation of $91.3 million, an increase in other comprehensive income of $16.9 million and a reduction to OG&E’s benefit obligations regulatory asset of $74.4 million (see Note 1).

12. Report of Business Segments

The Company’s business is divided into four segments for financial reporting purposes. These segments are as follows: (i) electric utility, which is engaged in the generation, transmission, distribution and sale of electric energy, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. 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 for the three months ended March 31, 2011 and 2010.

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
March 31, 2011	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)

Operating revenues	$	422.1	$	100.2	$	266.7	$	198.1		$	---		$	(146.6	)	$	840.5
Cost of goods sold		219.4		64.0		196.3		199.3			---			(145.8	)		533.2
Gross margin on revenues		202.7		36.2		70.4		(1.2	)		---			(0.8	)		307.3
Other operation and maintenance		105.8		9.1		26.8		2.1			(4.7	)		(0.8	)		138.3
Depreciation and amortization		51.8		5.4		13.5		---			3.3			---			74.0
Taxes other than income		19.1		4.3		1.9		0.2			1.6			---			27.1
Operating income (loss)	$	26.0	$	17.4	$	28.2	$	(3.5	)	$	(0.2	)	$	---		$	67.9

Total assets	$	5,826.2	$	2,132.2	$	1,028.8	$	73.4		$	2,792.7		$	(4,162.7	)	$	7,690.6

			Transportation		Gathering
Three Months Ended	Electric		and		and					Other
March 31, 2010	Utility		Storage		Processing		Marketing			Operations			Eliminations			Total
(In millions)

Operating revenues	$	444.0	$	111.1	$	247.9	$	245.7		$	---		$	(172.9	)	$	875.8
Cost of goods sold		250.8		66.2		180.0		244.3			---			(171.2	)		570.1
Gross margin on revenues		193.2		44.9		67.9		1.4			---			(1.7	)		305.7
Other operation and maintenance		93.9		11.0		21.3		2.7			(4.1	)		(1.2	)		123.6
Depreciation and amortization		49.7		5.4		12.4		---			2.8			---			70.3
Taxes other than income		17.7		3.9		1.9		0.2			1.3			---			25.0
Operating income (loss)	$	31.9	$	24.6	$	32.3	$	(1.5	)	$	---		$	(0.5	)	$	86.8

Total assets	$	5,421.6	$	1,535.9	$	876.5	$	122.9		$	2,654.8		$	(3,442.4	)	$	7,169.3

13. Commitments and Contingencies

Except as set forth below and in Note 14, the circumstances set forth in Notes 14 and 15 to the Company’s Consolidated Financial Statements included in the Company’s 2010 Form 10-K appropriately represent, in all material respects, the current status of the Company’s material commitments and contingent liabilities.

OG&E Railcar Lease Agreement

OG&E has a noncancellable operating lease with purchase options, covering 1,446 coal hopper railcars to transport coal from Wyoming to OG&E’s coal-fired generation units. Rental payments are charged to Fuel Expense and are recovered through OG&E’s tariffs and fuel adjustment clauses. On December 15, 2010, OG&E renewed the lease agreement effective February 1, 2011. At the end of the new lease term, which is February 1, 2016, OG&E has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If OG&E chooses not to purchase the railcars or renew the lease agreement and the actual fair value of the railcars is less than the stipulated fair market value, OG&E would be responsible for the difference in those values up to a maximum of $23.7 million.

On February 10, 2009, OG&E executed a short-term lease agreement for 270 railcars in accordance with new coal transportation contracts with BNSF Railway and Union Pacific. These railcars were needed to replace railcars that have been taken out of service or destroyed. The lease agreement expired with respect to 135 railcars on November 2, 2009 and was not replaced. The lease agreement with respect to the remaining 135 railcars expired on March 5, 2010 and is continuing on a month-to-month basis with a 30-day notice required by either party to terminate the agreement.

OG&E is also required to maintain all of the railcars it has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services and WATCO, both of which are non-affiliated companies, to furnish this maintenance.

OG&E Wholesale Agreement

On May 28, 2009, OG&E sent a termination notice to the Arkansas Valley Electric Cooperative that OG&E would terminate its wholesale power agreement to all points of delivery where OG&E sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011. In December 2010, OG&E and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby OG&E will supply wholesale power to the Arkansas

Valley Electric Cooperative through June 2015. On January 3, 2011, OG&E submitted this agreement to the FERC for approval. The FERC approved the new wholesale power agreement on March 2, 2011 and the new contract was effective May 1, 2011. The Arkansas Valley Electric Cooperative contract contributed $17.4 million, or 1.5 percent, to OG&E’s gross margin for the year ended December 31, 2010. The new Arkansas Valley Electric Cooperative contract is expected to add approximately $4 million in additional gross margin from May through December 2011 over the prior contract.

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, claims made by third parties, environmental actions or the action of various regulatory 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. Except as otherwise stated above, in Note 14 below, in Item 1 of Part II of this Form 10-Q, in Notes 14 and 15 of Notes to Consolidated Financial Statements and Item 3 of Part I of the Company’s 2010 Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will 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 15 to the Company’s Consolidated Financial Statements included in the Company’s 2010 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

Completed Regulatory Matter

OG&E SPP Cost Tracker

On October 7, 2010, OG&E filed an application with the OCC seeking recovery of the Oklahoma jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. OG&E requested authorization to implement a cost tracker in order to recover from its retail customers the third-party project costs discussed above and to collect its administrative SPP cost assessment levied under Schedule 1A of the SPP open access transmission tariff, which is currently recovered in base rates. OG&E also requested authorization to establish a regulatory asset effective January 1, 2011 in order to give OG&E the opportunity to recover such costs that will be paid but not recovered until the cost tracker is made effective. On February 8, 2011, all parties signed a settlement agreement in this matter which would allow OG&E to recover the costs discussed in (i) above through a recovery rider effective January 1, 2011. OG&E anticipates recovering $1.8 million of incremental revenues in 2011 through the rider. Rather than including the costs of the SPP administrative fee assessment in the recovery rider, the stipulating parties agreed to allow OG&E to include the projected 2012 level of the SPP administrative fee assessment in its anticipated Oklahoma rate case to be filed in the summer of 2011. The settlement agreement also stated that in OG&E’s 2011 Oklahoma general rate case filing, OG&E would propose that recovery in base rates for the costs of transmission projects it constructs and owns and that are authorized by the SPP in its regional planning processes should be limited to the Oklahoma retail jurisdictional share of the costs for such projects allocated to OG&E by the SPP. On March 28, 2011, the OCC issued an order in this matter approving the settlement agreement.

Pending Regulatory Matters

OG&E 2010 Arkansas Rate Case Filing

On September 28, 2010, OG&E filed a rate case with the APSC requesting a rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines and wind energy, that have been completed since the last rate filing in August 2008, as well as rising operating costs. OG&E also sought recovery, through a rider, of the Arkansas jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates and (ii) SPP administrative fees. On March 15, 2011, the APSC Staff filed its recommendation, which included a $4.8 million rate increase and approval of the SPP rider for third-party transmission charges and SPP administrative fees. OG&E filed its rebuttal testimony on April 5, 2011. On April 26, 2011, the APSC Staff filed surrebuttal testimony, which included

support for an $8.8 million rate increase and recommended approval of an SPP rider for recovery of third-party transmission charges and SPP administrative fees of $0.8 million. The Arkansas office of the Attorney General and other parties to the proceeding have not agreed to the $9.6 million rate increase recommended by the APSC Staff. A hearing in this matter is scheduled for May 24, 2011.

Review of OG&E’s Fuel Adjustment Clause for Calendar Year 2009

On October 29, 2010, the OCC Staff filed an application for a public hearing to review and monitor OG&E’s application of the 2009 fuel adjustment clause. On December 28, 2010, OG&E responded by filing the necessary information and documents to satisfy the OCC’s minimum filing requirement rules. An intervenor representing a group of OG&E’s industrial customers filed testimony on March 11, 2011 seeking a $15.5 million refund related to (i) a purported failure by OG&E to maximize the use of its coal-fired power plants and (ii) an inappropriate extension of the existing natural gas supply agreement between OG&E and Enogex. OG&E filed rebuttal testimony on April 4, 2011 in opposition to the claims of the intervenor. A hearing in this matter is scheduled for June 23, 2011.

OG&E Smart Grid Project

As previously reported in the Company’s 2010 Form 10-K, on December 17, 2010, OG&E filed an application with the APSC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant. A hearing in this matter is scheduled for June 27, 2011. OG&E expects to receive a decision from the APSC during the third quarter of 2011.

OG&E FERC Transmission Rate Incentive Filing

On February 18, 2011, OG&E submitted to the FERC a request seeking limited transmission rate incentives for five transmission projects. This February 18, 2011 request is in addition to the October 12, 2010 request described in the Company’s 2010 Form 10-K. OG&E requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five 345 kV EHV transmission projects to be constructed and owned by OG&E within the SPP’s region. OG&E also requested to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond OG&E’s control. On April 19, 2011, the FERC granted these incentives for the Sooner-Rose Hill, Sunnyside-Hugo and Balanced Portfolio 3E transmission projects discussed in Note 15 of the Company’s 2010 Form 10-K.

OG&E Pension Tracker Modification Filing

On February 22, 2011, OG&E filed an application with the OCC requesting that OG&E’s pension tracker be modified to include the difference between the level of retiree medical costs authorized in OG&E’s last rate case and the current level of these expenses as a regulatory liability, effective January 1, 2011. A procedural schedule has not been established in this matter.

OG&E Demand and Energy Efficiency Program Filing

To build on the success of its earlier programs and further promote energy efficiency and conservation for each class of OG&E customers, on March 15, 2011, OG&E filed an application with the APSC seeking approval of several programs, ranging from residential weatherization to commercial lighting. In seeking approval of these programs, OG&E also seeks recovery of the program and related costs through a rider that would be added to customers’ electric bills. In Arkansas, OG&E’s program is expected to cost $7 million over a three-year period and is expected to increase the average residential electric bill by $1.47 per month. A hearing in this matter is scheduled for May 16, 2011.

Enogex FERC Section 311 2007 Rate Case

On October 1, 2007, Enogex made its required triennial rate filing at the FERC to update its Section 311 maximum interruptible transportation rates for Section 311 service in the East Zone and West Zone. Enogex’s filing requested an increase in the maximum zonal rates and proposed to place such rates into effect on January 1, 2008. A number of parties intervened and some also filed protests. Enogex did not place the increased rates set forth in its October 2007 rate filing into effect but rather continued to provide interruptible Section 311 service under the maximum Section 311 rates for both zones approved by the FERC in the previous rate case. A final settlement was filed with the FERC on August 5, 2010 and an order is pending. With the filing of Enogex’s 2009 rate case discussed below, the rate period for the 2007 rate case became a limited locked-in period from January 2008 through May 2009.

On November 13, 2007, one of the protesting intervenors filed to consolidate the Enogex 2007 rate case with a separate Enogex application pending before the FERC allowing Enogex to lease firm capacity to MEP and with separate applications filed by MEP with the FERC for a certificate to construct and operate the MEP pipeline and to lease firm capacity from Enogex. Enogex and MEP separately opposed this intervenor’s protests and assertions in its initial and subsequent pleadings. On July 25, 2008, the FERC issued an order (i) approving the MEP project including the approval of a limited jurisdiction certificate and (ii) authorizing the Enogex lease agreement with MEP. Accordingly, Enogex proceeded with the construction of facilities necessary to implement this service. On August 25, 2008, a protestor sought rehearing which the FERC denied. Enogex commenced service to MEP under the lease agreement on June 1, 2009. On July 16, 2009, the protestor filed, with the United States Court of Appeals for the District of Columbia Circuit, a petition for review of the FERC’s orders approving the MEP construction and the MEP lease of capacity from Enogex requesting that such orders be modified or set aside on the grounds that they are arbitrary, capricious and contrary to law. On December 28, 2010, the Court of Appeals issued an opinion generally upholding the FERC’s orders, but remanding the case for further explanation of one aspect of the FERC’s reasoning. The Court of Appeals emphasized that it was not vacating the FERC’s orders and that its approval of the Enogex lease agreement with MEP remains in effect and legally binding. On remand, the FERC must clarify that its decision was based on a finding that the lease does not adversely affect existing customers on Enogex’s system. Enogex anticipates that the FERC will issue an order on remand in the first half of 2011. On January 21, 2011, Apache Corporation filed a motion asking the FERC to establish procedures on remand and to either condition the lease on Enogex’s willingness to provide firm Section 311 transportation service to existing customers on all portions of its system or to establish an expedited briefing schedule. On February 7, 2011, Enogex, MEP and Chesapeake Energy Corporation filed a joint answer asking the FERC to find, among other things, that the reduction in the amount of interruptible transportation capacity available due to the MEP lease did not have an adverse affect on Apache Corporation and to acknowledge that Apache Corporation’s request to condition the lease on the provision of West Zone 311 firm transportation service has been addressed as Enogex filed a rate case on January 28, 2011 proposing to implement such service effective March 1, 2011. On March 1, 2011, Apache Corporation filed an answer seeking to refute some of the arguments presented in the joint answer filed by Enogex, MEP and Chesapeake Energy Corporation. On March 3, 2011, the FERC issued an order on remand affirming the authorizations previously granted to Enogex and MEP and clarifying the legal standard applied in response to the court’s directive. On April 4, 2011, Apache Corporation filed a request for rehearing of the FERC’s order on remand. Once the FERC acts on Apache Corporation’s request for rehearing, the order on remand and the order on rehearing become subject to appeal before the United States Court of Appeals for the District of Columbia Circuit.

Enogex FERC Section 311 2009 Rate Case

On March 27, 2009, Enogex filed a petition for rate approval with the FERC to set the maximum rates for its new firm East Zone Section 311 transportation service and to revise the rates for its existing East and West Zone interruptible Section 311 transportation service. In anticipation of offering this new service, Enogex had filed with the FERC, as required by the FERC’s regulations, a revised SOC Applicable to Transportation Services to describe the terms, conditions and operating arrangements for the new service. Enogex made the SOC filing on February 27, 2009. Enogex began offering firm East Zone Section 311 transportation service on April 1, 2009. The revised East and West Zone zonal rates for the Section 311 interruptible transportation service became effective June 1, 2009. The rates for the firm East Zone Section 311 transportation service and the increase in the rates for East and West Zone and interruptible Section 311 service are being collected, subject to refund, pending the FERC approval of the proposed rates. A number of parties intervened in both the rate case and the SOC filing and some additionally filed protests. On January 4, 2010, the FERC Staff submitted an offer proposing various adjustments to Enogex’s filed cost of service. On April 27, 2010, Enogex submitted comments to the FERC Staff stating that it would agree to the offer, contingent upon all parties agreeing to support or not oppose. Parties have until June 6, 2011 to submit comments stating whether they support, or do not oppose, the FERC Staff’s offer.

Enogex FERC Section 311 2011 Rate Case

On January 28, 2011, Enogex submitted a new rate filing to the FERC to set the maximum rate for a new firm Section 311 transportation service in the West Zone of its system and to revise the currently effective maximum rates for Section 311 interruptible transportation service in the East Zone and West Zone. Along with establishing the rate for a new firm service in the West Zone, Enogex’s filing requested a decrease in the maximum interruptible zonal rates in the West Zone and to retain the currently effective rates for firm and interruptible services in the East Zone. Enogex reserved the right to implement the higher rates for firm and interruptible services in the East Zone supported by the cost of service to the extent an expeditious settlement agreement cannot be reached in the proceeding. Enogex proposed that the rates be placed into effect on March 1, 2011. On April 28, 2011, Enogex filed a motion with the FERC requesting an additional extension of the May 4, 2011 protest deadline until June 6, 2011. The regulations provide that the FERC has 150 days to act on the filing but also permit the FERC to issue an order extending the time period for action. No action has yet been taken by the FERC.

Enogex 2011 Fuel Filing

On February 28, 2011, Enogex submitted its annual fuel filing to establish the fixed fuel percentages for its East Zone and West Zone for the upcoming fuel year (April 1, 2011 through March 31, 2012). Along with the revised fuel percentages, Enogex also requested authority to revise its SOC to permanently change the annual filing date to February 28. The deadline for interventions and protests on Enogex’s filing was March 15, 2011, and no protests were filed. A FERC order is pending.

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

Introduction

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. Through OGE Holdings, 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. 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. Enogex LLC’s holdings also include a 50 percent ownership interest in Atoka.

Overview

Financial Strategy

The Company’s mission is to fulfill its critical role in the nation’s electric utility and natural gas midstream pipeline infrastructure and meet individual customers’ needs for energy and related services in a safe, reliable and efficient manner. The Company intends to execute its vision by focusing on its regulated electric utility business and unregulated natural gas midstream business. The Company intends to maintain the majority of its assets in the regulated utility business, however, the Company anticipates significant growth opportunities for its natural gas midstream business. With respect to its natural gas midstream business, the Company intends to focus on growing products and services with limited or manageable commodity price exposure and intends to seek to mitigate exposure to fluctuations in commodity prices by continuing to increase the percentage that fee-based processing agreements represent of the total processing volumes. 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 target payout ratio for the Company is to pay out as 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 March 31, 2011 as Compared to Three Months Ended March 31, 2010

Net income attributable to OGE Energy was $24.8 million, or $0.25 per diluted share, during the three months ended March 31, 2011, as compared to $24.2 million, or $0.25 per diluted share, during the same period in 2010. Included in net income attributable to OGE Energy for the three months ended March 31, 2010 was a one-time, non-cash charge of $11.4 million, or $0.11 per diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy (as previously reported in the Company’s 2010 Form 10-K). The increase in net income attributable to OGE Energy of $0.6 million, or 2.5 percent, during the three months ended March 31, 2011 as compared to the same period in 2010 was primarily due to:

an increase in net income at OG&E of $5.2 million, or $0.05 per diluted share of the Company’s common stock, primarily due to a higher gross margin primarily from the implementation of rate riders and lower income tax expense related to the Medicare Part D subsidy discussed above partially offset by higher operation and maintenance expense;

a decrease in net income at Enogex of $8.6 million or 31.4 percent, or $0.09 per diluted share of the Company’s common stock, primarily due to a lower gross margin. Gross margin during the three months ended March 31, 2010 included the recovery of prior years’ under-recovered fuel positions (which increased the first quarter 2010 gross margin by $6.7 million) and operational storage hedging activity (which increased the first quarter 2010 gross margin by $2.4 million), neither of which occurred in the first quarter of 2011. Higher operation and maintenance expense as well as the equity sale of a membership interest in Enogex Holdings to the ArcLight group also contributed to the decrease in net income. These factors were partially offset by lower income tax expense related to the Medicare Part D subsidy discussed above; and

an increase in net income at OGE Energy of $4.0 million or 92.3 percent, or $0.04 per diluted share of the Company’s common stock, primarily due to a higher income tax benefit related to the Medicare Part D subsidy discussed above.

Recent Developments and Regulatory Matters

OG&E SPP Cost Tracker

On March 28, 2011, the OCC approved OG&E’s request to recover, through a cost tracker, the Oklahoma jurisdictional portion of costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-OG&E transmission owners throughout the SPP that have been allocated to OG&E through the FERC-approved transmission rates. OG&E anticipates recovering $1.8 million of incremental revenues in 2011 through the rider. OG&E had requested the inclusion of the incremental SPP administrative fee assessment in the recovery rider. Rather than including these costs in the recovery rider, OG&E will include the projected 2012 level of the SPP administrative fee assessment in its anticipated Oklahoma rate case to be filed in the summer of 2011.

Enogex Sale of Harrah Processing Plant and Certain Gathering Assets

On April 1, 2011, Enogex completed the sale of its Harrah processing plant (38 MMcf/d of capacity) and the associated Wellston and Davenport gathering assets. The proceeds from the sale were approximately $16.1 million and Enogex expects to record a pre-tax gain in the second quarter of 2011 of approximately $3.0 million.

2011 Outlook

The Company’s 2011 earnings guidance remains unchanged and is between $299 million and $318 million of net income, or $3.00 to $3.20 per average diluted share. NGLs prices have strengthened significantly since the Company released its 2011 earnings guidance in February. Should prices of NGLs remain at their current levels for the balance of the year and if the other assumptions in the Company’s 2010 Form 10-K underlying the Company’s 2011 earnings guidance for Enogex remain on target, then the Company would expect Enogex to exceed the upper end of its stated range for 2011 of $0.90 to $1.05 of earnings per average diluted share. In addition, Enogex continues to pursue its stated plan to reduce its commodity price exposure by increasing the percentage that fee-based processing arrangements represent of its total processing volumes. Enogex is currently negotiating renewals/extensions of its gathering and processing contracts with one of Enogex’s larger customers that would increase the area dedicated to Enogex for gathering and processing for an extended term and would change the processing arrangement from keep-whole to fixed-fee. To the extent Enogex is successful in

these negotiations, Enogex would forego the short-term benefits that might otherwise be expected as a result of strong commodity prices under a keep-whole arrangement. As a result, if Enogex is successful in these negotiations and if the other assumptions in the Company’s 2010 Form 10-K underlying the Company’s 2011 earnings guidance for Enogex remain on target, then the Company would expect Enogex to be at the lower end of the guidance range of $0.90 to $1.05 of earnings per average diluted share for 2011. Despite the potential for lower earnings during times of high NGLs prices, the Company believes that new long-term gathering and processing agreements with fixed-fee processing arrangements are in the best interests of its shareholders. Please see the Company’s 2010 Form 10-K for the key factors and assumptions underlying its 2011 earnings guidance.

Results of Operations

The following discussion and analysis presents factors that affected the Company’s consolidated results of operations for the three months ended March 31, 2011 as compared to the same period in 2010 and the Company’s consolidated financial position at March 31, 2011. Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 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 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
	March 31,
(In millions, except per share data)	2011		2010
Operating income	$	67.9	$	86.8
Net income attributable to OGE Energy	$	24.8	$	24.2
Basic average common shares outstanding		97.7		97.1
Diluted average common shares outstanding		99.1		98.5
Basic earnings per average common share attributable to
OGE Energy common shareholders	$	0.25	$	0.25
Diluted earnings per average common share attributable to
OGE Energy common shareholders	$	0.25	$	0.25
Dividends declared per common share	$	0.3750	$	0.3625

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 (Loss) by Business Segment

	Three Months Ended
	March 31,
(In millions)	2011		2010
OG&E (Electric Utility)	$	26.0	$	31.9