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, 2010

OR

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).   o  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, 2010, there were 97,205,073 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2010

TABLE OF CONTENTS

	Page
FORWARD-LOOKING STATEMENTS	1
Part I – FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income	2
Condensed Consolidated Balance Sheets	3
Condensed Consolidated Statements of Changes in Stockholders’ Equity	5
Condensed Consolidated Statements of Cash Flows	6
Notes to Condensed Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3. Quantitative and Qualitative Disclosures About Market Risk	47
Item 4. Controls and Procedures	48
Part II – OTHER INFORMATION
Item 1. Legal Proceedings	48
Item 1A. Risk Factors	50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6. Exhibits	50
Signature	51

i

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. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” in OGE Energy Corp.’s Annual Report on Form   10-K for the year ended December 31, 2009 (“2009 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:

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

Ÿ   the ability of OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) and its subsidiaries to access the capital markets and obtain financing on favorable terms;

Ÿ   prices and availability of electricity, coal, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other;

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

Ÿ   competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;

Ÿ   unusual weather;

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

Ÿ   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;

Ÿ   environmental laws and regulations that may impact the Company’s operations;

Ÿ   changes in accounting standards, rules or guidelines;

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

Ÿ   creditworthiness of suppliers, customers and other contractual parties;

Ÿ   the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and

Ÿ   other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to the Company’s 2009 Form 10-K.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

1

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended
	March 31,
(In millions, except per share data)	2010		2009
OPERATING REVENUES
Electric Utility operating revenues	$	444.0	$	336.7
Natural Gas Pipeline operating revenues		431.8		269.9
Total operating revenues		875.8		606.6
COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)
Electric Utility cost of goods sold		238.9		159.1
Natural Gas Pipeline cost of goods sold		331.2		194.1
Total cost of goods sold		570.1		353.2
Gross margin on revenues		305.7		253.4
Other operation and maintenance		123.6		116.5
Depreciation and amortization		70.3		62.6
Taxes other than income		25.0		22.3
OPERATING INCOME		86.8		52.0
OTHER INCOME (EXPENSE)
Interest income		---		0.7
Allowance for equity funds used during construction		2.3		1.3
Other income		3.1		6.5
Other expense		(2.4)		(2.3)
Net other income		3.0		6.2
INTEREST EXPENSE
Interest on long-term debt		33.6		31.4
Allowance for borrowed funds used during construction		(1.2)		(1.1)
Interest on short-term debt and other interest charges		1.7		2.4
Interest expense		34.1		32.7
INCOME BEFORE TAXES		55.7		25.5
INCOME TAX EXPENSE		30.5		7.9
NET INCOME		25.2		17.6
Less: Net income attributable to noncontrolling interest		1.0		0.8
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	24.2	$	16.8
BASIC AVERAGE COMMON SHARES OUTSTANDING		97.1		94.7
DILUTED AVERAGE COMMON SHARES OUTSTANDING		98.5		95.3
BASIC EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.25	$	0.18
DILUTED EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.25	$	0.18
DIVIDENDS DECLARED PER SHARE	$	0.3625	$	0.3550

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

2

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
	March 31,		December 31,
	2010		2009
(In millions)	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5.7	$	58.1
Accounts receivable, less reserve of $1.9 and $2.4, respectively		262.1		291.4
Accrued unbilled revenues		46.3		57.2
Income taxes receivable		76.0		157.7
Fuel inventories		129.3		118.5
Materials and supplies, at average cost		81.7		78.4
Price risk management		4.9		1.8
Gas imbalances		4.4		3.2
Accumulated deferred tax assets		41.4		39.8
Fuel clause under recoveries		0.9		0.3
Prepayments		8.4		8.7
Other		8.7		11.0
Total current assets		669.8		826.1
OTHER PROPERTY AND INVESTMENTS, at cost		43.3		43.7
PROPERTY, PLANT AND EQUIPMENT
In service		8,846.1		8,617.8
Construction work in progress		188.0		335.4
Total property, plant and equipment		9,034.1		8,953.2
Less accumulated depreciation		3,074.5		3,041.6
Net property, plant and equipment		5,959.6		5,911.6
DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		38.8		19.1
Benefit obligations regulatory asset		350.3		357.8
Price risk management		0.4		4.3
Unamortized loss on reacquired debt		16.2		16.5
Unamortized debt issuance costs		14.9		15.3
Other		76.0		72.3
Total deferred charges and other assets		496.6		485.3
TOTAL ASSETS	$	7,169.3	$	7,266.7

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

3

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
	March 31,		December 31,
	2010		2009
(In millions)	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	341.6	$	175.0
Accounts payable		242.0		297.0
Dividends payable		35.2		35.1
Customer deposits		83.3		85.6
Accrued taxes		35.7		37.0
Accrued interest		25.7		60.6
Accrued compensation		35.4		50.1
Long-term debt due within one year		---		289.2
Price risk management		20.1		14.2
Gas imbalances		12.1		12.0
Fuel clause over recoveries		157.0		187.5
Other		32.0		32.4
Total current liabilities		1,020.1		1,275.7
LONG-TERM DEBT		2,204.0		2,088.9
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		373.0		369.3
Accumulated deferred income taxes		1,280.1		1,246.6
Accumulated deferred investment tax credits		12.2		13.1
Accrued removal obligations, net		173.0		168.2
Price risk management		1.4		0.1
Other		49.8		44.0
Total deferred credits and other liabilities		1,889.5		1,841.3
Total liabilities		5,113.6		5,205.9
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS’ EQUITY
Common stockholders’ equity		894.2		887.7
Retained earnings		1,216.7		1,227.8
Accumulated other comprehensive loss, net of tax		(76.2)		(74.7)
Total OGE Energy stockholders’ equity		2,034.7		2,040.8
Noncontrolling interest		21.0		20.0
Total stockholders’ equity		2,055.7		2,060.8
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,169.3	$	7,266.7

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

4

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(Unaudited)
		Premium		Accumulated
		on		Other
	Common	Capital	Retained	Comprehensive	Noncontrolling
	Stock	Stock	Earnings	Income (Loss)	Interest	Total
Balance at December 31, 2008	$         0.9	$     802.0	$   1,107.6	$              (13.7)	$                17.2	$  1,914.0
Comprehensive income (loss)
Net income for first quarter of 2009	---	---	16.8	---	0.8	17.6
Other comprehensive income (loss), net of tax
Defined benefit pension plan and restoration of
retirement income plan:
Amortization of deferred net loss, net of tax ($1.3 pre-     tax)	---	---	---	0.8	---	0.8
Defined benefit postretirement plans:
Amortization of deferred net loss, net of tax ($0.2 pre-     tax)	---	---	---	0.1	---	0.1
Deferred hedging losses, net of tax (($46.2) pre-tax)	---	---	---	(28.3)	---	(28.3)
Amortization of cash flow hedge, net of tax ($0.2 pre-tax)	---	---	---	0.1	---	0.1
Other comprehensive loss	---	---	---	(27.3)	---	(27.3)
Comprehensive income (loss)	---	---	16.8	(27.3)	0.8	(9.7)
Dividends declared on common stock	---	---	(34.2)	---	---	(34.2)
Issuance of common stock	0.1	55.7	---	---	---	55.8
Balance at March 31, 2009	$         1.0	$     857.7	$   1,090.2	$              (41.0)	$                18.0	$  1,925.9
Balance at December 31, 2009	$         1.0	$     886.7	$   1,227.8	$              (74.7)	$                20.0	$  2,060.8
Comprehensive income
Net income for first quarter of 2010	---	---	24.2	---	1.0	25.2
Other comprehensive income (loss), net of tax
Defined benefit pension plan and restoration of
retirement income plan:
Amortization of deferred net loss, net of tax ($1.2 pre-        tax)	---	---	---	0.5	---	0.5
Defined benefit postretirement plans:
Amortization of deferred net loss, net of tax ($1.0 pre-     tax)	---	---	---	0.6	---	0.6
Amortization of deferred net transition obligation,     net of tax ($0.2 pre-tax)	---	---	---	0.2	---	0.2
Amortization of prior service cost, net of tax (($0.2)        pre-tax)	---	---	---	(0.2)	---	(0.2)
Deferred hedging losses, net of tax (($4.3) pre-tax)	---	---	---	(2.7)	---	(2.7)
Amortization of cash flow hedge, net of tax ($0.1 pre-tax)	---	---	---	0.1	---	0.1
Other comprehensive loss	---	---	---	(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	---	6.5	---	---	---	6.5
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.

5

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
(In millions)	2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	25.2	$	17.6
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation and amortization		70.3		62.6
Deferred income taxes and investment tax credits, net		15.6		18.9
Allowance for equity funds used during construction		(2.3)		(1.3)
Loss on disposition and abandonment of assets		0.8		0.2
Stock-based compensation expense		2.0		1.4
Stock-based compensation converted to cash for tax withholding		(1.6)		(1.8)
Price risk management assets		0.7		(1.3)
Price risk management liabilities		3.1		(30.4)
Other assets		4.4		10.6
Other liabilities		0.6		(5.0)
Change in certain current assets and liabilities
Accounts receivable, net		29.3		48.7
Accrued unbilled revenues		10.9		5.9
Income taxes receivable		81.7		---
Fuel, materials and supplies inventories		(14.1)		(10.0)
Gas imbalance assets		(1.2)		4.7
Fuel clause under recoveries		(0.6)		24.0
Other current assets		1.8		2.5
Accounts payable		(30.4)		(60.0)
Customer deposits		0.4		0.9
Accrued taxes		(0.2)		(25.9)
Accrued interest		(34.9)		(16.2)
Accrued compensation		(14.7)		(16.0)
Gas imbalance liabilities		0.1		(8.3)
Fuel clause over recoveries		(30.5)		64.4
Other current liabilities		(0.4)		(24.8)
Net Cash Provided from Operating Activities		116.0		61.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(135.0)		(247.8)
Construction reimbursement		3.3		2.0
Proceeds from sale of assets		1.0		0.1
Other investing activities		0.1		---
Net Cash Used in Investing Activities		(130.6)		(245.7)
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(289.2)		---
Dividends paid on common stock		(35.1)		(33.3)
Issuance of common stock		4.9		56.1
Proceeds from line of credit		115.0		80.0
Increase in short-term debt, net		166.6		53.5
Net Cash (Used in) Provided from Financing Activities		(37.8)		156.3
NET DECREASE IN CASH AND CASH EQUIVALENTS		(52.4)		(28.0)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		58.1		174.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5.7	$	146.4

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

6

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.          Summary of Significant Accounting Policies

Organization

OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, 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 Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“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 LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting and storing 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 two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.  Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned subsidiary of Enogex Gathering & Processing LLC.  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 with a separate presentation for the noncontrolling interest.  Enogex is a Delaware single-member limited liability company.

In July 2008, OGE Energy and Electric Transmission America, a joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Co., formed a transmission joint venture, conducting business as Tallgrass Transmission L.L.C. (“Tallgrass”), to construct high-capacity transmission line projects.  The Company owns 50 percent of Tallgrass.  Tallgrass is intended to allow the participating companies to lead development of renewable wind by sharing capital costs associated with transmission construction.

The Company charges operating costs to its subsidiaries based on several factors.  Operating costs directly related to specific subsidiaries are assigned to those subsidiaries.  Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits.  Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, based primarily upon head-count, occupancy, usage or the “Distrigas” method.  The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment.  The Company adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff.  The Company believes this method provides a reasonable basis for allocating common expenses.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“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, 2010 and December 31, 2009 and the results of its operations and cash flows for the three months ended March 31, 2010 and 2009, have been included and are of a normal recurring nature except as otherwise disclosed.

7

Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 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 Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 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)	2010		2009
Regulatory Assets
Benefit obligations regulatory asset	$	350.3	$	357.8
Income taxes recoverable from customers, net		38.8		19.1
Deferred storm expenses		30.5		28.0
Deferred pension plan expenses		17.0		18.1
Unamortized loss on reacquired debt		16.2		16.5
Red Rock deferred expenses		7.6		7.7
Fuel clause under recoveries		0.9		0.3
Miscellaneous		2.3		3.9
Total Regulatory Assets	$	463.6	$	451.4
Regulatory Liabilities
Accrued removal obligations, net	$	173.0	$	168.2
Fuel clause over recoveries		157.0		187.5
Miscellaneous		6.6		7.3
Total Regulatory Liabilities	$	336.6	$	363.0

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 Cash Flows to conform to the 2010 presentation related to a customer’s reimbursement of Enogex’s costs related to the ongoing construction of a transportation pipeline in 2009 and 2010.

2.          Accounting Pronouncements

In December 2009, the Financial Accounting Standards Board (“FASB”) issued “Consolidations – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” which amends previously issued accounting guidance in this area.  The new standard applies to entities involved with variable interest entities (“VIE”). The new standard changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a reporting entity is required to consolidate another entity is based on, among other things, the other entity’s purpose and design and the reporting entity’s ability to direct the activities of the other entity that most significantly impact the other entity’s economic performance. The new standard

8

requires additional disclosures related to: (i) an entity’s involvement with VIE’s and (ii) any significant changes in risk exposure due to that involvement.  The new standard was effective for fiscal years beginning after November 15, 2009, and interim periods following initial adoption, with earlier application prohibited.  Upon initial application, prior periods are not required to be presented for comparative purposes.  The Company adopted this new standard effective January 1, 2010.  The adoption of this new standard did not have a material impact on the Company’s consolidated financial position or results of operations.

In January 2010, the FASB issued “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements,” which requires new disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in previously issued accounting guidance in this area.  The new standard requires additional disclosures related to: (i) the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers and(ii) presenting separate information about purchases, sales, issuances and settlements (on a gross basis) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3).  Also, the new standard clarifies the requirements of previously issued accounting guidance in this area related to: (i) a reporting entity’s need to use judgment in determining the appropriate classes of assets and liabilities and (ii) a reporting entity’s disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements.  The new standard was effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the rollforward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted.  The Company adopted this new standard effective January 1, 2010 and has included the required disclosures in Note 3.

In February 2010, the FASB issued “Subsequent Events,” which amends previously issued guidance in this area.  The new standard is applicable to all entities.  The new standard: (i) updates the glossary to include the definition of an SEC filer and to remove the definition of a public entity, (ii) removes the requirement for an SEC filer to disclose the date through which subsequent events have been evaluated and (iii) clarifies that the scope of the reissuance disclosure requirements will include revised financial statements only, which are financial statements revised either as a result of the correction of an error or retrospective application of GAAP.  The new standard does not change the guidance provided in the previous statement related to disclosure requirements for non-SEC filers.  This new standard was effective upon issuance on February 24, 2010, at which time the Company adopted this new standard.

3.          Fair Value Measurements

The following tables are a summary of the Company’s assets and liabilities that are measured at fair value on a recurring basis at March 31, 2010 and December 31, 2009.

	March 31,
(In millions)	2010		Level 1		Level 2		Level 3
Assets
Gross commodity contracts	$	87.0	$	35.2	$	10.8	$	41.0
Gas imbalance assets (A)		4.4		---		4.4		---
Total	$	91.4	$	35.2	$	15.2	$	41.0
Liabilities
Gross commodity contracts	$	101.0	$	32.9	$	59.9	$	8.2
Gas imbalance liabilities (A)(B)		8.4		---		8.4		---
Total	$	109.4	$	32.9	$	68.3	$	8.2

(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 approximately $3.7 million, 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.

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	December 31,
(In millions)	2009		Level 1		Level 2		Level 3
Assets
Gross commodity contracts	$	71.3	$	16.1	$	6.2	$	49.0
Gas imbalance assets (C)		3.2		---		3.2		---
Total	$	74.5	$	16.1	$	9.4	$	49.0
Liabilities
Gross commodity contracts	$	77.8	$	13.3	$	49.8	$	14.7
Gas imbalance liabilities (C)(D)		8.0		---		8.0		---
Total	$	85.8	$	13.3	$	57.8	$	14.7

(C) 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.

(D) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $4.0 million, 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 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 assets or liabilities that the reporting entity has the ability to access at the measurement date. An active market for the asset or liability is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.  An example of instruments that may be classified as Level 1 are futures transactions for energy commodities traded on the New York Mercantile Exchange (“NYMEX”).

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in markets that are not active, (iii) inputs other than quoted prices that are observable for the asset or liability or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. An example of instruments that may be classified as Level 2 includes energy commodity purchase or sales transactions in a market such that the pricing is closely related to the NYMEX pricing.

Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that observable inputs are not available.  Unobservable inputs shall 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). Unobservable inputs shall be developed based on the best information available in the circumstances, which might include the reporting entity’s own data. The reporting entity’s own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions. An example of instruments that may be classified as Level 3 includes energy commodity purchase or sales transactions of a longer duration or in an inactive market such that there are no closely related markets in which quoted prices are available.

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. Otherwise, they are considered Level 3.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services (“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.

The following table is a reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at March 31, 2010 and December 31, 2009.

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	March 31,		December 31,
(In millions)	2010		2009
Assets
Gross commodity contracts	$	87.0	$	71.3
Less:  Amounts held in clearing broker accounts reflected in Other Current Assets		35.6		17.3
Less:  Amounts offset under master netting agreements		46.1		47.9
Net Price Risk Management Assets	$	5.3	$	6.1
Liabilities
Gross commodity contracts	$	101.0	$	77.8
Less:  Amounts held in clearing broker accounts reflected in Other Current Assets		33.4		15.6
Less:  Amounts offset under master netting agreements		46.1		47.9
Net Price Risk Management Liabilities	$	21.5	$	14.3

The following table is a summary of the Company’s assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

Assets	Commodity Contracts
(In millions)	2010		2009
Balance at January 1	$	49.0	$	121.2
Transfers into Level 3		---		---
Transfers out of Level 3		---		---
Total gains or losses
Included in earnings		---		---
Included in other comprehensive income		(3.9)		(11.1)
Purchases, issuances, sales and settlements
Purchases		---		---
Issuances		---		---
Sales		---		---
Settlements		(4.1)		(4.5)
Balance at March 31	$	41.0	$	105.6
The amount of total gains or losses for the period included in earnings attributable
to the change in unrealized gains or losses relating to assets held at March 31	$	---	$	---

Liabilities	Commodity Contracts
(In millions)	2010		2009
Balance at January 1	$	14.7	$	---
Transfers into Level 3		---		---
Transfers out of Level 3		---		---
Total gains or losses
Included in earnings		---		---
Included in other comprehensive income		(5.1)		---
Purchases, issuances, sales and settlements
Purchases		---		---
Issuances		---		---
Sales		---		---
Settlements		(1.4)		---
Balance at March 31	$	8.2	$	---
The amount of total gains or losses for the period included in earnings attributable
to the change in unrealized gains or losses relating to liabilities held at March 31	$	---	$	---

Gains and losses (realized and unrealized) included in earnings for the three months ended March 31, 2010 and 2009 attributable to the change in unrealized gains or losses relating to assets and liabilities held at March 31, 2010 and 2009, if any, are reported in Operating Revenues.

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The following table is a summary of the fair value and carrying amount of the Company’s financial instruments, including derivative contracts related to the Company’s Price Risk Management (“PRM”) activities at March 31, 2010 and December 31, 2009.

	March 31, 2010						December 31, 2009
	Carrying			Fair			Carrying		Fair
(In millions)	Amount			Value			Amount		Value
Price Risk Management Assets
Energy Derivative Contracts	$	5.3	$		5.3	$	6.1	$		6.1
Price Risk Management Liabilities
Energy Derivative Contracts	$	21.5	$		21.5	$	14.3	$		14.3
Long-Term Debt
OG&E Senior Notes	$	1,406.4	$		1,477.2	$	1,406.4	$		1,492.1
OGE Energy Senior Notes		99.6			104.8		99.5			102.6
OG&E Industrial Authority Bonds		135.4			135.4		135.4			135.4
Enogex Senior Notes		447.6			462.6		736.8			746.7
Enogex Revolving Credit Agreement		115.0			115.0		---			---

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 hedging and 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 management’s estimate 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. The commodity price swap contracts involve the exchange of fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity.  The commodity price option contracts involve the payment of a premium for the right, but not the obligation, to exchange fixed price or rate payments for floating price or rate payments over the life of the instrument without an exchange of the underlying commodity.  Commodity derivative instruments used by the Company are as follows:

Ÿ   natural gas liquids (“NGL”) put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;

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

Ÿ   natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OGE Energy’s natural gas marketing subsidiary, OGE Energy Resources, Inc.’s (“OERI”), natural gas exposure associated with its storage and transportation contracts; and

Ÿ   natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OERI’s marketing and trading activities.

Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement discussed above as normal purchases and normal sales contracts.  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.

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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 debt, treasury lock agreements and commercial paper.  The Company from time to time uses treasury lock agreements to manage its interest rate risk exposure on new debt issuances. Additionally, the Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates.  The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce interest expense related to existing debt issues.  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.  Under the change in fair value method, 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. The ineffectiveness of treasury lock cash flow hedges is measured using the hypothetical derivative method.  Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected.  Forecasted transactions 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.  If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings.

At March 31, 2010 and December 31, 2009, the Company had no outstanding treasury lock agreements that were designated as cash flow hedges.

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The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s contractual long/short positions and operational storage natural gas, keep-whole natural gas and NGLs hedges.  Enogex’s cash flow hedging activity at March 31, 2010 covers the period from April 1, 2010 through December 31, 2011.  The Company also designates certain derivatives used to manage commodity exposure for certain transportation and natural gas inventory positions at OERI. OERI does not have any derivative instruments designated as cash flow hedges at March 31, 2010.  At March 31, 2010, the Company had the following outstanding commodity derivative instruments that were designated as cash flow hedges.

		Notional
	Commodity	Volume (A)		Maturity
	(volumes in millions)
Short Financial Swaps/Futures (fixed)	NGLs		0.4	Current
Purchased Financial Options	NGLs		1.3	Current
Purchased Financial Options	NGLs		1.0	Non-Current
Total Purchased Financial Options			2.3
Long Financial Swaps/Futures (fixed)	Natural Gas		6.0	Current
Long Financial Swaps/Futures (fixed)	Natural Gas		3.9	Non-Current
Total Long Financial Swaps/Futures (fixed)			9.9
Short Financial Swaps/Futures (fixed)	Natural Gas		1.4	Current
Short Financial Basis Swaps	Natural Gas		1.4	Current

(A) Natural gas in million British thermal unit (“MMBtu”); NGLs in barrels. All volumes are presented on a gross basis.

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, 2010 and December 31, 2009, the Company had no outstanding commodity derivative instruments or treasury lock agreements that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

For derivative instruments not designated as either a cash flow or fair value hedge, the gain or loss on the derivative is recognized currently in earnings. Derivative instruments not designated as either a cash flow or a fair value hedge are utilized in OERI’s asset management, marketing and trading activities.  Derivative instruments not designated as either cash flow or fair value hedges also include contracts formerly designated as cash flow hedges of Enogex’s NGLs, keep-whole natural gas and operational storage natural gas exposures.  A portion of Enogex’s processing agreements, which were previously under keep-whole arrangements, were converted to fee-based arrangements.  As a result, effective June 30, 2009 Enogex de-designated a portion of these derivatives and entered into offsetting derivatives to close the positions. Also, effective November 12, 2009, in response to market opportunities Enogex elected to de-designate its operational storage hedges and entered into offsetting derivatives to close the positions.

At March 31, 2010, the Company had the following outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge.

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		Notional
	Commodity	Volume (A)		Maturity
	(volumes in millions)
Short Financial Swaps/Futures (fixed)	NGLs		0.6	Current
Long Financial Swaps/Futures (fixed)	NGLs		0.6	Current
Physical Purchases (B)	Natural Gas		26.0	Current
Physical Purchases (B)	Natural Gas		4.0	Non-Current
Total Physical Purchases			30.0
Physical Sales (B)	Natural Gas		26.9	Current
Physical Sales (B)	Natural Gas		9.6	Non-Current
Total Physical Sales			36.5
Long Financial Swaps/Futures (fixed)	Natural Gas		31.5	Current
Long Financial Swaps/Futures (fixed)	Natural Gas		1.0	Non-Current
Total Long Financial Swaps/Futures (fixed)			32.5
Short Financial Swaps/Futures (fixed)	Natural Gas		30.6	Current
Short Financial Swaps/Futures (fixed)	Natural Gas		2.7	Non-Current
Total Short Financial Swaps/Futures (fixed)			33.3
Purchased Financial Option	Natural Gas		22.0	Current
Sold Financial Option	Natural Gas		21.5	Current
Long Financial Basis Swaps	Natural Gas		11.6	Current
Long Financial Basis Swaps	Natural Gas		1.0	Non-Current
Total Long Financial Basis Swaps			12.6
Short Financial Basis Swaps	Natural Gas		8.7	Current
Short Financial Basis Swaps	Natural Gas		1.0	Non-Current
Total Short Financial Basis Swaps			9.7
(A) Natural gas in MMBtu; NGLs in barrels. All volumes are presented on a gross basis.
(B) Of the natural gas physical purchases and sales volumes not designated as cash flow or fair value 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.

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

				Fair Value
		Balance Sheet
Instrument	Commodity	Location		Assets			Liabilities
(dollars in millions)
Derivatives Designated as Hedging Instruments
Financial Options	NGLs	Current PRM	$		18.5	$		---
		Non-Current PRM			17.0			---
Financial Futures/Swaps	NGLs	Current PRM			---			2.4
Financial Futures/Swaps	Natural Gas	Current PRM			---			24.1
		Non-Current PRM			---			18.4
		Other Current Assets			5.3			0.2
Total Gross Derivatives Designated as Hedging Instruments			$		40.8	$		45.1

(A)  

15

Derivatives Not Designated as Hedging Instruments
Financial Futures/Swaps (A)	NGLs	Current PRM	$	5.5	$	5.8
Financial Futures/Swaps (B)	Natural Gas	Current PRM		5.1		14.9
		Other Current Assets		28.4		31.6
Physical Purchases/Sales	Natural Gas	Current PRM		4.9		2.0
		Non-Current PRM		0.4		---
Financial Options	Natural Gas	Other Current Assets		1.9		1.6
Total Gross Derivatives Not Designated as Hedging Instruments			$	46.2	$	55.9
Total Gross Derivatives (C)			$	87.0	$	101.0

(A)	The fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions.  The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $5.5 million and Current Liabilities of approximately $5.8 million.
(B)	The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions.  The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $4.7 million and Current Liabilities of approximately $14.0 million.
(C)	See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at March 31, 2010 (see Note 3).

Credit-Risk Related Contingent Features in Derivative Instruments

In the event Moody’s Investors Service or Standard & Poor’s were to lower the Company’s senior unsecured debt rating to a below investment grade rating, at March 31, 2010, the Company would have been required to post approximately $18.0 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, 2010.  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.

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.

									Amount of
									Gain or Loss
					Amount of		Location of Gain or		Recognized
					Gain or Loss		Loss Recognized in		in Income on
	Amount of Gain				Reclassified		Income on		Derivative
	or Loss				from		Derivative		(Ineffective
	Recognized in			Location of Gain or	Accumulated		(Ineffective Portion		Portion and
	OCI on			Loss Reclassified	OCI into		and Amount		Amount
	Derivative			from Accumulated	Income		Excluded from		Excluded from
	(Effective			OCI into Income	(Effective		Effectiveness		Effectiveness
Instrument	Portion)(A)			(Effective Portion)	Portion)		Testing)		Testing)
(dollars in millions)
Derivatives in Cash Flow Hedging Relationships
NGLs Financial Options		$	0.5	Operating Revenues	$	(0.6)	Operating Revenues	$		---
NGLs Financial
Futures/Swaps			1.3	Operating Revenues		(1.4)	Operating Revenues			---
Natural Gas Financial
Futures/Swaps			(9.9)	Operating Revenues		(3.3)	Operating Revenues			0.1
Total		$	(8.1)	Total	$	(5.3)	Total	$		0.1

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at March 31, 2010 that is expected to be reclassified into  earnings within the next 12 months is a loss of approximately $25.9 million.

16

		Amount of Gain or
	Location of Gain or	Loss Recognized in
	Loss Recognized in	Income of
	Income on Derivative	Derivative
		(dollars in millions)
Derivatives Not Designated as Hedging Instruments
Natural Gas Physical Purchases/Sales	Operating Revenues	$	(0.1)
Natural Gas Financial Futures/Swaps	Operating Revenues		0.7
Total		$	0.6

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, currency 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, currency 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.

5.          Stock-Based Compensation

On January 21, 1998, the Company adopted a Stock Incentive Plan (the “1998 Plan”) and in 2003, the Company adopted another Stock Incentive Plan (the “2003 Plan” that replaced the 1998 Plan).  In 2008, the Company adopted, and its shareowners approved, a new Stock Incentive Plan (the “2008 Plan” and together with the 1998 Plan and the 2003 Plan, the “Plans”).  The 2008 Plan replaced the 2003 Plan and no further awards will be granted under the 2003 Plan or the 1998 Plan. As under the 2003 Plan and the 1998 Plan, under the 2008 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of the Company and its subsidiaries.  The Company has authorized the issuance of up to 2,750,000 shares under the 2008 Plan.

The Company recorded compensation expense of approximately $2.1 million pre-tax ($1.3 million after tax, or $0.01 per basic and diluted share) and approximately $1.4 million pre-tax ($0.8 million after tax, or $0.01 per basic and diluted share) during the three months ended March 31, 2010 and 2009, respectively, related to the Company’s share-based payments.

During the three months ended March 31, 2010, the Company awarded 213,533 performance units based on total shareholder return and 71,179 performance units based on earnings per share with a grant date fair value of $39.43 and $32.44, respectively, to certain employees of the Company and its subsidiaries.  Also, during the three months ended March 31, 2010, the Company converted 105,103 performance units based on a payout ratio of 120.69 percent of the target number of performance units granted in February 2007.

The Company issues new shares to satisfy stock option exercises and payouts of earned performance units.  During the three months ended March 31, 2010, there were 138,933 shares of new common stock issued pursuant to the Company’s Plans related to exercised stock options and payouts of earned performance units. The Company received approximately $1.2 million during the three months ended March 31, 2010 related to exercised stock options.  There were no exercised stock options during the three months ended March 31, 2009.

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6.          Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive loss at March 31, 2010 and December 31, 2009 are as follows:

	March 31,		December 31,
(In millions)	2010		2009
Defined benefit pension plan and restoration of retirement income plan:
Net loss, net of tax (($64.4) and ($65.6) pre-tax, respectively)	$	(39.5)	$	(40.0)
Prior service cost, net of tax (($1.0) and ($1.1) pre-tax, respectively)		(0.7)		(0.7)
Defined benefit postretirement plans:
Net loss, net of tax (($20.8) and ($21.2) pre-tax, respectively)		(10.1)		(10.7)
Net transition obligation, net of tax (($0.4) and ($0.6) pre-tax, respectively)		(0.2)		(0.4)
Prior service cost, net of tax (($0.3) and ($0.1) pre-tax, respectively)		(0.2)		---
Deferred hedging gains (losses), net of tax (($39.8) and ($35.5) pre-tax,
respectively)		(24.4)		(21.7)
Deferred hedging losses on interest rate swaps, net of tax (($1.8) and ($1.9) pre-
tax, respectively)		(1.1)		(1.2)
Total accumulated other comprehensive loss, net of tax	$	(76.2)	$	(74.7)

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 2006 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.  This ratable amortization results in a larger percentage reconciling item related to these credits during the first quarter when the Company historically experiences decreased book income.  OG&E earns both Federal and Oklahoma state tax credits associated with the production from its 120 megawatt (“MW”) wind farm in northwestern Oklahoma and its 101 MW OU Spirit wind farm in western Oklahoma (“OU Spirit”).  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.

The Company estimated a Federal tax net operating loss for 2009 primarily caused by the accelerated tax depreciation provisions contained within the American Recovery and Reinvestment Act of 2009 (“ARRA”).  ARRA allowed a current deduction for 50 percent of the cost of certain property placed into service during 2009.  This tax loss resulted in an approximate $68 million current income tax receivable related to the 2009 tax year.  On November 6, 2009, the Worker, Homeownership, and Business Assistance Act of 2009 was signed into law by the President.  This new law provided for a five-year carry back of net operating losses incurred in 2008 or 2009.  This expanded carryback period enabled the Company to carry back the entire 2009 tax loss. A carryback claim was filed in March 2010 and a refund of approximately $68 million was received by the Company in April 2010.

Medicare Part D Subsidy

On March 23, 2010, the Patient Protection and Affordable Care Act of 2009 (the “Patient Protection Act”) was signed into law, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 (the “Reconciliation Act” and, together with Patient Protection Act, the “Acts”), which makes various amendments to certain aspects of the Patient Protection Act, was signed into law.  The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D.

The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Medicare Act”).  The Company has been recognizing the federal subsidy since 2005 related to certain retiree prescription drug plans that were determined to be actuarially equivalent to the benefit provided under Medicare Part D. Under the Medicare Act, the federal subsidy does not reduce an employer’s income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually.

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Under the Acts, beginning in 2013 an employer’s income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Under GAAP, any impact from a change in tax law must be recognized in earnings in the period enacted regardless of the effective date.  As retiree healthcare liabilities and related tax impacts are already reflected in the Company’s Condensed Consolidated Financial Statements, the Company recognized a one-time, non-cash charge of approximately $11.4 million, or $0.11 per diluted share, during the quarter ended March 31, 2010 for the write-off of previously recognized tax benefits relating to Medicare Part D subsidies to reflect the change in the tax treatment of the federal subsidy.

8.           Common Equity

Automatic Dividend Reinvestment and Stock Purchase Plan

In November 2008, the Company filed a Form S-3 Registration Statement to register 5,000,000 shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan (“DRIP/DSPP”).  The Company issued 101,745 shares of common stock under its DRIP/DSPP during the three months ended March 31, 2010 and received proceeds of approximately $3.7 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, 2010, there were 2,890,999 shares of unissued common stock reserved for issuance under the Company’s DRIP/DSPP.

Earnings Per Share

Outstanding shares for purposes of basic and diluted earnings per average common share were calculated as follows:

	Three Months Ended
	March 31,
(In millions)	2010		2009
Average Common Shares Outstanding
Basic average common shares outstanding		97.1		94.7
Effect of dilutive securities:
Contingently issuable shares (performance units)		1.4		0.6
Diluted average common shares outstanding		98.5		95.3
Anti-dilutive shares excluded from EPS calculation		---		---

9.         Long-Term Debt

At March 31, 2010, the Company was in compliance with all of its debt agreements.

OG&E has three series of variable-rate industrial authority bonds (the “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 (dollars in millions):

SERIES	DATE DUE	AMOUNT
0.30% - 0.40%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.35% - 0.52%	Muskogee Industrial Authority, January 1, 2025		32.4
0.33% - 0.49%	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-

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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 approximately $341.6 million and $175.0 million at March 31, 2010 and December 31, 2009, respectively.  The following table provides information regarding the Company’s revolving credit agreements and available cash at March 31, 2010.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding (A)		Interest Rate	Maturity
OGE Energy (B)	$	596.0	$	341.6	0.29% (D)	December 6, 2012
OG&E (C)		389.0		9.5	--- % (D)	December 6, 2012
Enogex (E)		250.0		115.0	0.54% (D)	March 31, 2013
		1,235.0		466.1	0.35%
Cash		5.7		N/A	N/A	N/A
Total	$	1,240.7	$	466.1	0.35%
(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at March 31, 2010. (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, 2010, there were no outstanding borrowings under this revolving credit agreement and approximately $341.6 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, 2010, there was approximately $9.5 million supporting letters of credit.  There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at March 31, 2010. (D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements and commercial paper borrowings. (E) This bank facility is available to provide revolving credit borrowings for Enogex.  As Enogex’s credit agreement matures on March 31, 2013, borrowings thereunder are classified as long-term debt in the Company’s Condensed Consolidated Balance Sheets.

OGE Energy’s and OG&E’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 back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the ratings of OGE Energy or OG&E would result in an increase in the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes. Any future downgrade of the Company would 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, 2009 and ending December 31, 2010.

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11.       Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of the 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)	2010		2009		2010		2009
Service cost	$	4.4	$	4.5	$	0.2	$	0.2
Interest cost		7.8		7.8		0.1		0.1
Return on plan assets		(10.7)		(8.2)		---		---
Amortization of net loss		5.1		5.9		0.1		0.1
Amortization of unrecognized prior service cost		0.6		0.2		0.1		0.1
Net periodic benefit cost (A)	$	7.2	$	10.2	$	0.5	$	0.5
(A) In addition to the approximately $7.7 million and $10.7 million of net periodic benefit cost recognized during the three months ended March 31, 2010 and 2009, respectively, the Company recognized an increase in pension expense during the three months ended March 31, 2010 of approximately $1.9 million and a reduction in pension expense of approximately $1.1 million during the three months ended March 31, 2009 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)	2010		2009
Service cost	$	1.2	$	0.8
Interest cost		4.2		3.5
Return on plan assets		(1.7)		(1.6)
Amortization of transition obligation		0.7		0.7
Amortization of net loss		2.7		1.2
Amortization of unrecognized prior service cost		---		0.3
Net periodic benefit cost	$	7.1	$	4.9

Pension Plan Funding

The Company previously disclosed in its 2009 Form 10-K that it may contribute up to $50 million to its pension plan during 2010.  In April 2010, the Company contributed approximately $20 million to its pension plan and currently expects to contribute an additional $30 million to its pension plan during the remainder of 2010.  Any remaining expected contributions to its pension plan during 2010 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.

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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, 2010 and 2009.

			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	$	1,503.0	$	876.5	$	122.9	$	2,654.8	$	(3,409.5)	$	7,169.3

			Transportation		Gathering
Three Months Ended	Electric		and		and				Other
March 31, 2009	Utility		Storage		Processing		Marketing		Operations		Eliminations		Total
(In millions)
Operating revenues	$	336.7	$	108.3	$	138.5	$	192.3	$	---	$	(169.2)	$	606.6
Cost of goods sold		171.0		66.2		96.1		187.8		---		(167.9)		353.2
Gross margin on revenues		165.7		42.1		42.4		4.5		---		(1.3)		253.4
Other operation and maintenance		85.3		9.9		23.1		2.6		(3.3)		(1.1)		116.5
Depreciation and amortization		45.5		4.7		10.1		---		2.3		---		62.6
Taxes other than income		16.1		3.6		1.3		0.2		1.1		---		22.3
Operating income (loss)	$	18.8	$	23.9	$	7.9	$	1.7	$	(0.1)	$	(0.2)	$	52.0
Total assets	$	4,963.2	$	1,348.0	$	846.0	$	176.8	$	2,461.6	$	(3,188.1)	$	6,607.5

13.       Commitments and Contingencies

Except as set forth below and in Note 14, the circumstances set forth in Notes 13 and 14 to the Company’s Consolidated Financial Statements included in the Company’s 2009 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

At March 31, 2010, OG&E had a noncancellable operating lease with purchase options, covering 1,462 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.  At the end of the lease term, which is January 31, 2011, 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 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 approximately $31.5 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

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replaced.  The lease agreement with respect to the remaining 135 railcars expired on March 5, 2010 and is now 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.

Oxley Litigation

OG&E has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma.  This case has been pending for more than 11 years.  The plaintiffs alleged that OG&E breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs in amounts set forth in the contracts.  The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages  (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. The arbitration hearing was completed recently and the final briefs were provided to the arbitration panel on March 17, 2010.  A ruling by the panel is expected in the second quarter of 2010.  While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

Natural Gas Measurement Cases

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I).  On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands.  On April 10, 2003, the court entered an order denying class certification.  On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003.  In its amended petition (the “Fourth Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two of the Company’s other subsidiary entities remained as defendants.  The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of the Company’s subsidiary entities, have improperly measured the volume of natural gas.  The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment.  In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion.  The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest.  The plaintiffs also reserved the right to seek punitive damages.

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues.  A hearing on class certification issues was held April 1, 2005.  In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action.  The court has not yet ruled on the motion to intervene.

The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007.  On September 18, 2009, the court entered its order denying class certification.  On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.

The Company intends to vigorously defend this action.  At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II).  On May 12, 2003, the plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the Fourth Amended Petition of the Price I case.  OG&E and Enogex Inc. were not named in this case, but two subsidiary entities of the Company were named in this case.  The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs.  In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion.  The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest.  The plaintiffs also reserved the right to seek punitive damages.

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Discovery was conducted on the class certification issues, and the parties fully briefed these same issues.  A hearing on class certification issues was held April 1, 2005.  In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action.  The court has not yet ruled on the motion to intervene.

The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007.  On September 18, 2009, the court entered its order denying class certification.  On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.

The Company intends to vigorously defend this action.  At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Pipeline Rupture

On November 14, 2008, a natural gas gathering pipeline owned by Enogex ruptured in Grady County, near Alex, Oklahoma, resulting in a fire that caused injuries to one resident and destroyed three residential structures.  After the incident, Enogex coordinated and assisted the affected residents.  Enogex resolved matters with two of the residents and Enogex continued to seek resolution with a remaining resident.  This resident filed a legal action in May 2009 in the District Court of Cleveland County, Oklahoma, against OGE Energy and Enogex.  This matter was resolved by the parties on April 8, 2010.  The ultimate resolution of this incident was not material to the Company in light of previously established reserves and insurance coverage.

Franchise Fee Lawsuit 

On June 19, 2006, two OG&E customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on OG&E’s electric bills.  The plaintiffs claim that OG&E improperly charged sales tax based on franchise fee charges paid by its customers.  The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. OG&E’s motion for summary judgment was denied by the trial judge.  OG&E filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit.  In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC.  In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes OG&E to collect the challenged franchise fee charges.  On March 10, 2009, the Oklahoma Attorney General, OG&E, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed.  On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the 1994 OCC order which authorized OG&E to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether OG&E’s collection and remittance of such sales tax should be discontinued prospectively. On December 21, 2009, the plaintiffs filed a motion at the Oklahoma Supreme Court asking the court to deny OG&E’s writ of prohibition and to remand the cause to the District Court. On December 29, 2009, the Oklahoma Supreme Court declared the plaintiffs’ motion moot. On January 27, 2010, the OCC Staff filed a motion asking the OCC to dismiss the cause and close the cause at the OCC.  On April 19, 2010, the OCC issued a final order dismissing with prejudice the applicants’ claims for recovery of previously paid taxes on franchise fees and approving the closing of this matter.

Environmental Matters

Water

OG&E filed Oklahoma Pollutant Discharge Elimination permit renewal applications for its Muskogee, Mustang and Horseshoe Lake generating stations on March 4, 2009, April 3, 2009 and October 29, 2009, respectively, and have received draft permits for review. Preliminary comments have been submitted to the Oklahoma Department of Environmental Quality for OG&E’s Mustang and Horseshoe Lake generating stations. The Muskogee generating station draft permit is currently being reviewed.

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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 accounting principles generally accepted in the United States, 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 13 and 14 of Notes to the Company’s Consolidated Financial Statements included in the Company’s 2009 Form 10-K and in Item 3 of that report, 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 14 to the Company’s Consolidated Financial Statements included in the Company’s 2009 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

Completed Regulatory Matters

OG&E Windspeed Transmission Line Project

OG&E filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma (“Windspeed”). The OCC subsequently authorized recovery at a construction cost of up to approximately $218 million, including allowance for funds used during construction (“AFUDC”).  At March 31, 2010, the construction costs and AFUDC incurred for the Windspeed transmission line were approximately $200.3 million and the final costs are expected to be less than $218 million.  The Windspeed transmission line was placed into service on March 31, 2010, with the recovery rider being implemented with the first billing cycle in April 2010.

Pending Regulatory Matters

OG&E Smart Grid Application

In February 2009, the ARRA was enacted into law. Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy.  After review of the ARRA, OG&E filed a grant request on August 4, 2009 for $130 million with the U.S. Department of Energy (“DOE”) to be used for the Smart Grid application in OG&E’s service territory.  On October 27, 2009, OG&E received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million, which will not be subject to income tax.  Receipt of the grant monies was contingent upon successful negotiations with the DOE on final details of the award.  On April 21, 2010, OG&E and the DOE entered into a definitive agreement with regards to the award.  On March 15, 2010, OG&E filed an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant.  A procedural schedule has not been established in this matter.

Separately, on November 30, 2009, OG&E requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for OG&E’s workforce.  In April 2010, OG&E was notified that it was not a recipient of the training grant.

OG&E Long-Term Gas Supply Agreements

On February 26, 2010, OG&E filed an application with the OCC requesting a waiver of the competitive bid rules to negotiate desired long-term gas purchase agreements.  A hearing is scheduled for May 13, 2010 in this matter.

OG&E Arkansas OU Spirit Application and Renewable Energy Filing

OG&E expects to file an application with the APSC in May 2010, requesting approval to recover from Arkansas customers the cost of OU Spirit through a surcharge and approval to recover, through the fuel adjustment clause, the costs of purchasing power under two wind purchase power agreements totaling 280 MWs, which were signed in September 2009, as a result of a request for proposal issued by OG&E in December 2008.  The agreements are both 20-year power purchase

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agreements, under which the developers are to build, own and operate the wind generating facilities and OG&E will purchase their electric output.  The two wind farms are expected to be in service by the end of 2010.

OG&E Crossroads Wind Project Application

OG&E signed memoranda of understanding in February 2010 for approximately 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind project (“Crossroads”) located in Dewey County, Oklahoma.  OG&E will build, own and operate the wind farm, if approved by the OCC.  On April 8, 2010, OG&E filed an application with the OCC requesting pre-approval of this project and a rider to recover from Oklahoma customers the costs to construct Crossroads.  A procedural schedule has not been established in this matter. Crossroads is expected to cost approximately $397.6 million with a related annual revenue requirement of approximately $40.0 million, of which approximately $34.5 million is the Oklahoma jurisdictional portion.

Enogex 2010 Fuel Filing

Pursuant to its Statement of Operating Conditions (“SOC”), Enogex makes an annual fuel filing at the FERC to establish the zonal fuel percentages for each calendar year.  The tracker mechanism set out in the SOC establishes prospectively the zonal fixed fuel factors (expressed as a percentage of natural gas shipped in the zone) for the upcoming calendar year.  The collected fuel is later trued-up to actual usage and based on the value of the fuel at the time of usage.

On November 23, 2009, Enogex made its annual filing to establish the fixed fuel percentages for its East Zone and West Zone for calendar year 2010 (“2010 Fuel Year”).  The FERC accepted the proposed zonal fuel percentages for the 2010 Fuel Year by an order dated April 23, 2010.

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

Introduction

OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, 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.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas.  Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“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 LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas midstream services.  Enogex is engaged in the business of gathering, processing, transporting and storing 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 two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing.  Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned subsidiary of Enogex Gathering & Processing LLC.

Executive 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 midstream natural gas business.  The Company intends to maintain the majority of its assets in the regulated utility business complemented by its natural gas pipeline business.  The Company’s financial objectives from 2010 through 2012 include a long-term annual earnings growth rate of five to seven percent on a weather-normalized basis as well as an annual dividend growth rate of two percent subject to approval by the Company’s Board of Directors.  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

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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, 2010 as Compared to Three Months Ended March 31, 2009

Net income attributable to OGE Energy was approximately $24.2 million, or $0.25 per diluted share, during the three months ended March 31, 2010, as compared to approximately $16.8 million, or $0.18 per diluted share, during the same period in 2009.  Included in net income attributable to OGE Energy during the three months ended March 31, 2010 was a one-time, non-cash charge of approximately $11.4 million, or $0.11 per diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements).  The increase in net income attributable to OGE Energy of approximately $7.4 million, or 44.0 percent, or $0.07 per diluted share, during the three months ended March 31, 2010 as compared to the same period in 2009 was primarily due to an increase in net income at Enogex of approximately $12.0 million, or $0.12 per diluted share of the Company’s common stock, mainly attributable to higher commodity prices and volumes, which offset decreases in net income at OG&E, OGE Energy Resources, Inc. (“OERI”) and the holding company.  In particular,

Ÿ   net income at OG&E was approximately $1.2 million during the three months ended March 31, 2010 as compared to approximately $1.3 million during the same period in 2009, which was a decrease in net income of approximately $0.1 million or 7.7 percent, or less than $0.01 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to higher other operation and maintenance expense, higher depreciation and amortization expense and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements) partially offset by a higher gross margin on revenues (“gross margin”) primarily due to cooler weather, rate increases and riders;

Ÿ   net income at Enogex was approximately $27.4 million during the three months ended March 31, 2010 as compared to approximately $15.4 million during the same period in 2009, which was an increase in net income of approximately $12.0 million or 77.9 percent, or $0.12 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to a higher gross margin, as a result of higher processing spreads, higher natural gas liquids (“NGL”) prices and volumes and higher natural gas prices and volumes partially offset by higher depreciation and amortization expense, higher interest expense and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements);

Ÿ   net loss at OGE Energy was approximately $3.3 million during the three months ended March 31, 2010 as compared to approximately $0.8 million during the same period in 2009, which was an increase in the net loss of approximately $2.5 million, or $0.03 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements); and

Ÿ   net loss at OERI was approximately $1.1 million during the three months ended March 31, 2010 as compared to net income of approximately $0.9 million during the same period in 2009, which was a decrease in net income of approximately $2.0 million, or $0.02 per diluted share of the Company’s common stock, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to a lower gross margin partially offset by lower income tax expense.

Timing Items.  Enogex’s net income for the three months ended March 31, 2010 was approximately $27.4 million, which included a realized gain of approximately $1.5 million related to the March 2010 component of Enogex’s operational storage hedges. This amount will be offset by a realized loss of approximately $1.0 million upon recognition of the May 2010 component of Enogex’s operational storage hedges, which are currently deferred in Accumulated Other Comprehensive Income.

Enogex’s net income for the three months ended March 31, 2009 was approximately $15.4 million, which included a realized gain of approximately $3.3 million related to the March 2009 component of Enogex’s operational storage hedges.

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This amount was offset by a realized loss of approximately $1.5 million upon recognition of the May 2009 component of Enogex’s operational storage hedges.

Recent Developments and Regulatory Matters

Volatility in the Commodity Markets

Enogex’s gathering and processing margins generally improve when NGLs prices, both on an actual basis and also relative to the price of natural gas (sometimes referred to as high commodity spreads), are high.  For much of the first nine months of 2008, commodity spreads and NGLs prices were relatively high.  However, later in 2008, both commodity spreads and NGLs prices were significantly lower.  During 2009 and through the first quarter of 2010, commodity spreads and NGLs prices increased over year-end 2008 levels but remained below the higher levels experienced in mid-2008.  Enogex expects the volatility in these markets to continue.

Global Climate Change and Environmental Concerns

There is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the Federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions.   In June 2009, the U.S. House of Representatives passed legislation that would regulate greenhouse gas emissions by instituting a cap-and-trade-system, in which a cap on U.S. greenhouse gas emissions would be established starting in 2012 at a level three percent below the baseline 2005 level. The cap would decline over time until in 2050 it reaches 83 percent below the baseline level. Emission allowances, which are rights to emit greenhouse gases, would be both allocated for free and auctioned. In addition, the legislation contains a renewable energy standard of 25 percent by the year 2025 and an energy efficiency mandate for electric and natural gas utilities, as well as other requirements. Legislation pending in the U.S. Senate proposes to regulate greenhouse gas emissions by instituting a cap-and-trade-system, with primarily the same target levels proposed by the House bill; however, the proposed Senate bill is more aggressive in its 2020 target – a reduction to 20 percent below 2005 levels by 2020 (versus 17 percent in the House bill). It is uncertain at this time whether, and in what form, such legislation will ultimately be adopted.  If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional capital expenditures and compliance costs.

Uncertainty surrounding global climate change and environmental concerns related to new coal-fired generation development is changing the mix of the potential sources of new generation in the region.  Adoption of renewable portfolio standards would be expected to increase the region’s reliance on wind generation.  The Company believes it can leverage its unique geographic position to develop renewable energy resources for wind and transmission to deliver the renewable energy.

OG&E Windspeed Transmission Line Project

OG&E filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma (“Windspeed”). The OCC subsequently authorized recovery at a construction cost of up to approximately $218 million, including allowance for funds used during construction (“AFUDC”).  At March 31, 2010, the construction costs and AFUDC incurred for the Windspeed transmission line were approximately $200.3 million and the final costs are expected to be less than $218 million.  The Windspeed transmission line was placed into service on March 31, 2010, with the recovery rider being implemented with the first billing cycle in April 2010.

OG&E Smart Grid Application

In February 2009, the American Recovery and Reinvestment Act of 2009 (“ARRA”) was enacted into law.  Several provisions of this law relate to issues of direct interest to the Company including, in particular, financial incentives to develop smart grid technology, transmission infrastructure and renewable energy.  After review of the ARRA, OG&E filed a grant request on August 4, 2009 for $130 million with the U.S. Department of Energy (“DOE”) to be used for the Smart Grid application in OG&E’s service territory.  On October 27, 2009, OG&E received notification from the DOE that its grant had been accepted by the DOE for the full requested amount of $130 million, which will not be subject to income tax.  Receipt of the grant monies was contingent upon successful negotiations with the DOE on final details of the award.  On April 21, 2010, OG&E and the DOE entered into a definitive agreement with regards to the award.   On March 15, 2010, OG&E filed an application with the OCC requesting pre-approval for system-wide deployment of smart grid technology and a recovery rider, including a credit for the Smart Grid grant.  A procedural schedule has not been established in this matter.

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Separately, on November 30, 2009, OG&E requested a grant with a 50 percent match of up to $5 million for a variety of types of smart grid training for OG&E’s workforce.  In April 2010, OG&E was notified that it was not a recipient of the training grant.

OG&E Crossroads Wind Project Application

OG&E signed memoranda of understanding in February 2010 for approximately 197.8 megawatts (“MW”) of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with the Crossroads wind project (“Crossroads”) located in Dewey County, Oklahoma.  OG&E will build, own and operate the wind farm, if approved by the OCC.  On April 8, 2010, OG&E filed an application with the OCC requesting pre-approval of this project and a rider to recover from Oklahoma customers the costs to construct Crossroads.  A procedural schedule has not been established in this matter. Crossroads is expected to cost approximately $397.6 million with a related annual revenue requirement of approximately $40.0 million, of which approximately $34.5 million is the Oklahoma jurisdictional portion.

Gathering and Processing System Expansions

Southeastern Oklahoma / East Side Expansions

Enogex plans to construct a new compressor station in Coal County, Oklahoma, as well as approximately 10 miles of gathering pipe and related treating facilities.  The station would be designed to accommodate up to 6,700 horsepower of low pressure compression and would be supported by approximately five miles of 20-inch steel pipe and five miles of 12-inch steel pipe.  The new compressor station will also include the purchase of associated gas treating facilities for the incremental gas in this area.  The initial 2,700 horsepower at the compressor station, and the gathering pipe, are currently in service, with an incremental 2,700 horsepower that went into service in March 2010.  The treating facilities are expected to be completed in the third quarter of 2010; however, Enogex will use its blending capabilities to accept gas for throughput until such time as the treating facilities have been constructed.  The capital expenditures for this project are expected to be approximately $22 million.

In order to gather additional volume in southeast Oklahoma, Enogex plans to construct an additional low pressure compressor station in Pittsburg County, Oklahoma.  This station is expected to include approximately 5,400 horsepower of compression, together with leased treating facilities.  The station is expected to be fully operational by November 2010, with capital expenditures of approximately $13 million.

Texas Panhandle / West Side Expansions

Enogex is planning to further expand its gathering infrastructure in 2010 in the Wheeler County, Texas area with the construction of approximately 15 miles of 10-inch steel pipe, as well as the addition of approximately 2,700 horsepower of compression.  The gathering pipelines are expected to be in service by the end of the third quarter of 2010, while the compression is expected to be operational by July 2010.  The capital expenditures associated with this project are expected to be approximately $12 million.

2010 Outlook

The Company’s 2010 ongoing earnings guidance remains unchanged and is between approximately $265 million and $290 million of net income, or $2.70 to $2.95 per average diluted share.  The Company now projects ongoing earnings to be at the upper end of the earnings range primarily due to Enogex’s ongoing earnings which are anticipated to be at the top end of the earnings range.

2010 Ongoing Earnings Guidance:

 Ÿ   Excludes a one-time, non-cash charge recorded in March 2010 of approximately $11.4 million, or $0.11 per average diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy.  Approximately $7.0 million is related to OG&E, approximately $2.0 million is related to Enogex and approximately $2.4 million is related to the holding company.

 Ÿ   Includes a projected increase for the remainder of 2010 in income tax expense of approximately $2.3 million, or $0.02 per average diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy.  Approximately $1.9 million is related to OG&E, approximately $0.2 million is related to Enogex and approximately $0.2 million is related to the holding company.

All other assumptions are unchanged from those included in the earnings guidance in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”).

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Ongoing earnings, which as indicated above excludes the one-time, non-cash charge of approximately $11.4 million associated with the elimination of the tax deduction for the Medicare Part D subsidy as a result of the recent health care legislation, is a non-GAAP financial measure.  As the Medicare Part D tax subsidy represents a charge which management believes will not be recurring on a regular basis, management believes that the presentation of Ongoing Earnings and Ongoing Earnings per Average Diluted Share (“EPS”) provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods.  Reconciliations of Ongoing Earnings and Ongoing EPS to generally accepted accounting principles (“GAAP”) net income and GAAP EPS are provided below.

Reconciliation of projected ongoing earnings to projected GAAP net income

(In millions)	Twelve Months Ended December 31, 2010
		OG&E				Enogex				Holding Company				Consolidated
		Low		High		Low		High		Low		High		Low		High
Ongoing earnings	$	207.0	$	217.0	$	63.0	$	85.0	$	(9.0)	$	(7.0)	$	265.0	$	290.0
Medicare Part D tax subsidy		(7.0)		(7.0)		(2.0)		(2.0)		(2.4)		(2.4)		(11.4)		(11.4)
Projected GAAP net income	$	200.0	$	210.0	$	61.0	$	83.0	$	(11.4)	$	(9.4)	$	253.6	$	278.6

Reconciliation of projected ongoing EPS to projected GAAP EPS

	Twelve Months Ended December 31, 2010
		OG&E				Enogex				Holding Company				Consolidated
		Low		High		Low		High		Low		High		Low		High
Ongoing EPS	$	2.10	$	2.20	$	0.64	$	0.86	$	(0.09)	$	(0.07)	$	2.70	$	2.95
Medicare Part D tax subsidy		(0.07)		(0.07)		(0.02)		(0.02)		(0.02)		(0.02)		(0.11)		(0.11)
Projected GAAP EPS	$	2.03	$	2.13	$	0.62	$	0.84	$	(0.11)	$	(0.09)	$	2.59	$	2.84

Earnings before Interest, Taxes, Depreciation and Amortization (“EBITDA”) is used as a supplemental financial measure by external users of the Company’s financial statements such as investors, commercial banks and others; therefore, the Company has included the table below which provides a reconciliation of projected EBITDA to projected ongoing net income attributable to Enogex LLC at the upper end of Enogex’s earnings assumptions for 2010.

Reconciliation of projected EBITDA to projected ongoing net income attributable to Enogex LLC

	Twelve Months Ended
(In millions)	December 31, 2010 (A)
Ongoing net income attributable to Enogex LLC	$	85.0
Add:
Interest expense, net		33.0
Income tax expense		54.0
Depreciation and amortization		69.0
EBITDA	$	241.0

(A)   At the upper end of Enogex’s earnings assumptions for 2010.

For a discussion of the reasons for the use of Ongoing Earnings, Ongoing EPS and EBITDA, as well as their limitations as analytical tools, see “Non-GAAP Financial Measures” below.

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, 2010 as compared to the same period in 2009 and the Company’s consolidated financial position at March 31, 2010.  Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 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.

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	Three Months Ended
	March 31,
(In millions, except per share data)	2010		2009
Operating income	$	86.8	$	52.0
Net income attributable to OGE Energy	$	24.2	$	16.8
Basic average common shares outstanding		97.1		94.7
Diluted average common shares outstanding		98.5		95.3
Basic earnings per average common share attributable to
OGE Energy common shareholders	$	0.25	$	0.18
Diluted earnings per average common share attributable to
OGE Energy common shareholders	$	0.25	$	0.18
Dividends declared per share	$	0.3625	$	0.3550

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)	2010		2009
OG&E (Electric Utility)	$	31.9	$	18.8
Enogex (Natural Gas Pipeline)
Transportation and storage		24.6		23.9
Gathering and processing		32.3		7.9
OERI (Natural Gas Marketing)		(1.5)		1.7
Other Operations (A)		(0.5)		(0.3)
Consolidated operating income	$	86.8	$	52.0

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

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

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OG&E (Electric Utility)

	Three Months Ended
	March 31,
(Dollars in millions)	2010		2009
Operating revenues	$	444.0	$	336.7
Cost of goods sold		250.8		171.0
Gross margin on revenues		193.2		165.7
Other operation and maintenance		93.9		85.3
Depreciation and amortization		49.7		45.5
Taxes other than income		17.7		16.1
Operating income		31.9		18.8
Interest income		---		0.5
Allowance for equity funds used during construction		2.3		1.3
Other income		2.5		4.6
Other expense		0.6		0.5
Interest expense		24.2		24.3
Income tax expense (benefit)		10.7		(0.9)
Net income	$	1.2	$	1.3
Operating revenues by classification
Residential	$	191.2	$	136.3
Commercial		101.0		79.4
Industrial		45.5		32.8
Oilfield		35.6		28.9
Public authorities and street light		39.5		31.5
Sales for resale		16.7		12.7
Provision for rate refund		---		(0.2)
System sales revenues		429.5		321.4
Off-system sales revenues (A)		6.4		5.9
Other		8.1		9.4
Total operating revenues	$	444.0	$	336.7
MWH (B) sales by classification (in millions)
Residential		2.4		2.0
Commercial		1.4		1.4
Industrial		0.9		0.9
Oilfield		0.7		0.7
Public authorities and street light		0.7		0.6
Sales for resale		0.3		0.3
System sales		6.4		5.9
Off-system sales		0.1		0.2
Total sales		6.5		6.1
Number of customers		778,574		771,909
Average cost of energy per KWH (C) - cents
Natural gas		5.593		3.793
Coal		1.793		1.544
Total fuel		3.281		2.226
Total fuel and purchased power		3.551		2.575
Degree days (D)
Heating - Actual		2,140		1,675
Heating - Normal		1,963		1,963
Cooling - Actual		8		23
Cooling - Normal		8		8
(A)  Sales to other utilities and power marketers. (B)  Megawatt-hour. (C)  Kilowatt-hour. (D) Degree days are calculated as follows:  The high and low degrees of a particular day are added together and then averaged.  If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day.  If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day.  The daily calculations are then totaled for the particular reporting period.

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Three Months Ended March 31, 2010 as Compared to Three Months Ended March 31, 2009

Operating Income

OG&E’s operating income increased approximately $13.1 million, or 69.7 percent, during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to a higher gross margin partially offset by higher other operation and maintenance expense and higher depreciation and amortization expense as discussed below.

Gross Margin

Gross margin was approximately $193.2 million during the three months ended March 31, 2010 as compared to approximately $165.7 million during the same period in 2009, an increase of approximately $27.5 million, or 16.6 percent.  The gross margin increased primarily due to:

Ÿ   cooler weather in OG&E’s service territory, which increased the gross margin by approximately $11.6 million;

Ÿ   increased price variance, which included revenues from various rate riders, including the Redbud Facility rider, the storm cost recovery rider, the system hardening rider, the OU Spirit wind farm in western Oklahoma (“OU Spirit”) rider, the Centennial wind farm rider and the Oklahoma demand program rider, and higher revenues from the sales and customer mix, which increased the gross margin by approximately $9.5 million;

Ÿ   the $48.3 million Oklahoma rate increase in which the majority of the annual increase is recovered during the summer months, which increased the gross margin by approximately $4.0 million;

Ÿ   revenues from the Arkansas rate increase, which increased the gross margin by approximately $2.1 million; and

Ÿ   new customer growth in OG&E’s service territory, which increased the gross margin by approximately $1.6 million.

These increases in the gross margin were partially offset by lower transmission revenues as a result of fewer transmission service requests from others on OG&E’s system, which decreased the gross margin by approximately $1.3 million.

Cost of goods sold for OG&E consists of fuel used in electric generation, purchased power and transmission related charges.  Fuel expense was approximately $198.6 million during the three months ended March 31, 2010 as compared to approximately $130.4 million during the same period in 2009, an increase of approximately $68.2 million, or 52.3 percent, primarily due to higher natural gas prices and increased natural gas generation.  OG&E’s electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for OG&E and its customers.  Purchased power costs were approximately $51.7 million during the three months ended March 31, 2010 as compared to approximately $40.1 million during the same period in 2009, an increase of approximately $11.6 million, or 28.9 percent, primarily due to an increase in purchases in the energy imbalance service market.

Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to OG&E’s customers through fuel adjustment clauses.  The fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC.  The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees OG&E pays to Enogex.

Operating Expenses

Other operation and maintenance expenses were approximately $93.9 million during the three months ended March 31, 2010 as compared to approximately $85.3 million during the same period in 2009, an increase of approximately $8.6 million, or 10.1 percent.  The increase in other operation and maintenance expenses was primarily due to:

Ÿ   an increase of approximately $4.8 million in salaries and wages expense primarily due to salary increases in 2010, increased incentive compensation expense and increased overtime expense due to the ice storm in January 2010;

Ÿ   an increase of approximately $3.5 million in contract technical and construction services attributable to increased spending for ongoing maintenance at some of OG&E’s power plants in the first quarter of 2010 as compared to the same period in 2009; and

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Ÿ   an increase of approximately $1.7 million in postretirement benefit plan expense primarily due to an increase in medical costs and changes in actuarial assumptions in 2010.

These increases in other operation and maintenance expenses were partially offset by an increase in capitalized labor primarily due to certain January 2010 ice storm costs being recorded as a regulatory asset as Deferred Storm Expenses (see Note 1) as well as certain costs being capitalized in conjunction with OG&E’s Smart Grid Program during the first quarter of 2010, which decreased other operation and maintenance expense by approximately $3.6 million.

Depreciation and amortization expense was approximately $49.7 million during the three months ended March 31, 2010 as compared to approximately $45.5 million during the same period in 2009, an increase of approximately $4.2 million, or 9.2 percent, primarily due to additional assets being placed into service, including OU Spirit that was placed into service in November and December 2009.

Taxes other than income were approximately $17.7 million during the three months ended March 31, 2010 as compared to approximately $16.1 million during the same period in 2009, an increase of approximately $1.6 million, or 9.9 percent, primarily due to higher ad valorem taxes.

Additional Information

Allowance for Equity Funds Used During Construction.  Allowance for equity funds used during construction (“AEFUDC”) was approximately $2.3 million during the three months ended March 31, 2010 as compared to approximately $1.3 million during the same period in 2009, an increase of approximately $1.0 million, or 76.9 percent, primarily due to construction costs associated with OU Spirit and the Windspeed transmission line constructed by OG&E which was placed in service on March 31, 2010.

Other Income.  Other income includes, among other things, contract work performed, non-operating rental income and miscellaneous non-operating income. Other income was approximately $2.5 million during the three months ended March 31, 2010 as compared to approximately $4.6 million during the same period in 2009, a decrease in other income of approximately $2.1 million, or 45.7 percent.  Other income decreased by approximately $2.4 million during the first quarter of 2010 due to an increased level of gains recognized in the guaranteed flat bill program during the first quarter of 2009 from lower than expected usage resulting from milder weather in addition to more customers participating in the guaranteed flat bill program during the first quarter of 2010 with higher than expected usage resulting from cooler weather.

Income Tax Expense (Benefit).  Income tax expense was approximately $10.7 million during the three months ended March 31, 2010 as compared to an income tax benefit of approximately $0.9 million during the same period in 2009, an increase in income tax expense of approximately $11.6 million primarily due to higher pre-tax income in the first quarter of 2010 as compared to the same period in 2009 and an adjustment for the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements).

Enogex (Natural Gas Transportation and Storage and Natural Gas Gathering and Processing)

	Transportation		Gathering
Three Months Ended	and		and
March 31, 2010	Storage		Processing		Eliminations		Total
(In millions)
Operating revenues	$	111.1	$	247.9	$	(74.8)	$	284.2
Cost of goods sold		66.2		180.0		(74.8)		171.4
Gross margin on revenues		44.9		67.9		---		112.8
Other operation and maintenance		11.0		21.3		---		32.3
Depreciation and amortization		5.4		12.4		---		17.8
Taxes other than income		3.9		1.9		---		5.8
Operating income	$	24.6	$	32.3	$	---	$	56.9

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	Transportation		Gathering
Three Months Ended	and		and
March 31, 2009	Storage		Processing		Eliminations		Total
(In millions)
Operating revenues	$	108.3	$	138.5	$	(56.7)	$	190.1
Cost of goods sold		66.2		96.1		(56.7)		105.6
Gross margin on revenues		42.1		42.4		---		84.5
Other operation and maintenance		9.9		23.1		---		33.0
Depreciation and amortization		4.7		10.1		---		14.8
Taxes other than income		3.6		1.3		---		4.9
Operating income	$	23.9	$	7.9	$	---	$	31.8

Operating Data

	Three Months Ended
	March 31,
	2010		2009
Gathered volumes – TBtu/d (A)		1.28		1.24
Incremental transportation volumes – TBtu/d (B)		0.46		0.42
Total throughput volumes – TBtu/d		1.74		1.66
Natural gas processed – TBtu/d		0.74		0.64
Natural gas liquids sold (keep-whole) – million gallons		43		21
Natural gas liquids sold (purchased for resale) – million gallons		99		70
Natural gas liquids sold (percent-of-liquids) – million gallons		7		8
Total natural gas liquids sold – million gallons		149		99
Average sales price per gallon	$	1.047	$	0.625
Estimated realized keep-whole spreads (C)	$	5.79	$	2.85

(A) Trillion British thermal units per day (“TBtu/d”).

(B) Incremental transportation volumes consist of natural gas moved only on the transportation pipeline.

(C) The estimated realized keep-whole spread is an approximation of the spread between the weighted-average sales price of the retained NGLs commodities and the purchase price of the replacement natural gas shrink.  The spread is based on the market commodity spread less any gains or losses realized from keep-whole hedging transactions.  The market commodity spread is estimated using the average of the Oil Price Information Service daily average posting at the Conway, Kansas market for the NGLs and the Inside FERC monthly index posting for Panhandle Eastern Pipe Line Co., Texas, Oklahoma, for the forward month contract for natural gas prices.

Three Months Ended March 31, 2010 as Compared to Three Months Ended March 31, 2009

Operating Income

Enogex’s operating income increased approximately $25.1 million, or 78.9 percent, during the three months ended March 31, 2010 as compared to the same period in 2009.  These increases are primarily due to higher processing spreads, higher NGLs prices, higher natural gas prices, increased volumes and higher gallons per million cubic foot (“GPM”) of natural gas associated with expansion projects.  The second quarter 2009 implementation of the Section 311 firm east side service, Midcontinent Express Pipeline, LLC (“MEP”) and Gulf Crossing capacity leases, and the addition of the Bennington compressor station increasing line capacity led to increased transportation revenues.  The fourth quarter 2009 addition of the new higher efficiency Clinton processing plant enabled Enogex to optimize recoveries across all processing plants.  In the normal course of Enogex’s business, the operation of its gathering, processing and transportation assets results in the creation of physical natural gas long/short positions. These physical positions can result from gas imbalances, actual versus contractual settlement differences, fuel tracker obligations and natural gas received in-kind for compensation or reimbursements.  Enogex actively manages its monthly net position through either selling excess gas or purchasing additional gas needs from third parties.  During the three months ended March 31, 2010, higher volumes and realized margin on physical gas long/short positions increased the gross margin by approximately $4.5 million, net of corresponding imbalance and fuel tracker obligations.  Also, in the normal course of Enogex’s business, Enogex maintains natural gas inventory to provide operational support for its pipeline deliveries.  All natural gas inventory held by Enogex is recorded at the lower of cost or market which could result in adjustments at the end of a reporting period.

Operation and maintenance expense decreased approximately $0.7 million, or 2.1 percent, primarily due to a decrease in technical and professional services and a decrease in materials and supplies primarily due to the delay of non-capitalized projects as a result of inclement weather during the first quarter of 2010.  These decreases were partially offset by

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higher salaries and benefits expense as a result of higher retirement benefits and a decrease in the amount of capitalized labor due to fewer capital projects in the first quarter of 2010.

Depreciation and amortization expense increased approximately $3.0 million, or 20.3 percent, primarily due to property, plant and equipment placed into service in 2009 and the first quarter of 2010.

Transportation and Storage

The transportation and storage business contributed approximately $44.9 million of Enogex’s consolidated gross margin during the three months ended March 31, 2010 as compared to approximately $42.1 million in the same period in 2009, an increase of approximately $2.8 million, or 6.7 percent.  The transportation operations contributed approximately $33.8 million of Enogex’s consolidated gross margin during the three months ended March 31, 2010 as compared to approximately $34.2 million in the same period in 2009.  The storage operations contributed approximately $11.1 million of Enogex’s consolidated gross margin during the three months ended March 31, 2010 as compared to approximately $7.9 million in the same period in 2009. The transportation and storage gross margin increased primarily due to:

Ÿ   lower natural gas market prices resulted in the recognition of a lower of cost or market adjustment to the natural gas storage inventory of approximately $5.8 million during the three months ended March 31, 2009 with no comparable item during the three months ended March 31, 2010;

Ÿ   new capacity lease service under the MEP and Gulf Crossing capacity leases that were placed into service in the second quarter of 2009 that increased transportation fees by approximately $4.5 million; and

Ÿ   implementation of the new Section 311 firm East side service during the second quarter of 2009 that increased transportation fees by approximately $1.4 million.

These increases in the transportation and storage gross margin were partially offset by:

Ÿ   decreased crosshaul volumes as fewer customers moved natural gas to eastern markets in the first quarter of 2010 as there were smaller differences in natural gas prices at various U.S. market locations, which decreased the gross margin by approximately $4.1 million; and

Ÿ   lower realized margins on operational storage hedges as the result of a decrease in volumes being transacted upon during the three months ended March 31, 2010, which decreased the gross margin by approximately $3.0 million.

Operation and maintenance expense for the transportation and storage business was approximately $1.1 million, or 11.1 percent, higher during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to higher salaries and benefits expense as a result of higher retirement benefits and a decrease in the amount of capitalized labor due to fewer capital projects in the first quarter of 2010.

Gathering and Processing

The gathering and processing business contributed approximately $67.9 million of Enogex’s consolidated gross margin during the three months ended March 31, 2010 as compared to approximately $42.4 million in the same period in 2009, an increase of approximately $25.5 million, or 60.1 percent. The gathering operations contributed approximately $30.1 million of Enogex’s consolidated gross margin during the three months ended March 31, 2010 as compared to approximately $24.2 million in the same period in 2009.  The processing operations contributed approximately $37.8 million of Enogex’s consolidated gross margin during the three months ended March 31, 2010 as compared to approximately $18.2 million in the same period in 2009.

During the three months ended March 31, 2010, Enogex realized a higher gross margin in its gathering and processing operations primarily as the result of higher processing spreads, higher NGLs prices and higher natural gas prices.  Enogex’s processing plants saw a 15.7 percent increase in inlet volumes associated with gathering expansion projects and an increase in NGLs production as recent expansion projects have added richer gas to the system.  Additionally, several plants were in ethane rejection for part of the first quarter of 2009 as compared to ethane recovery in the first quarter of 2010.  The fourth quarter 2009 completion of the new higher efficiency Clinton processing plant allowed Enogex to optimize recoveries across all processing plants. Overall, the above factors resulted in the following:

Ÿ   increased gross margin on keep-whole processing of approximately $5.9 million from higher spreads between NGLs prices and natural gas prices and higher plant efficiencies in the first quarter of 2010;

Ÿ   increased fixed processing fees of approximately $4.0 million; and

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Ÿ   increased gross margin on NGLs retained under percent-of-liquids contracts of approximately $3.1 million.

Other factors that contributed to the increase in the gathering and processing gross margin were:

Ÿ   an increase in condensate revenues associated with the gathering and processing operations due to increases in prices and volumes as a result of cooler weather during the first quarter of 2010 and several new expansion projects with higher GPM gas, which increased the gross margin by approximately $6.4 million;

Ÿ   higher volumes and realized margin on sales of physical natural gas long/short positions associated with gathering operations, which increased the gross margin by approximately $5.3 million net of imbalance and fuel tracker obligations; and

Ÿ   increased volumes associated with gathering expansion projects partially offset by cold weather events resulting in freeze-offs of producing wells and a short-term interruption of NGLs transportation services from most of Enogex’s processing plants, which increased the gross margin by approximately $0.5 million.

Other operation and maintenance expense for the gathering and processing business was approximately $1.8 million, or 7.8 percent, lower during the three months ended March 31, 2010 as compared to the same period in 2009 primarily due to the delay of non-capitalized projects as a result of inclement weather during the first quarter of 2010.

Enogex Consolidated Information

Interest Expense.  Enogex’s consolidated interest expense was approximately $8.2 million during the three months ended March 31, 2010 as compared to approximately $5.9 million during the same period in 2009, an increase of approximately $2.3 million, or 39.0 percent, primarily due to a decrease in capitalized interest related to lower capital expenditures in the first quarter of 2010 as compared to the same period in 2009.

Income Tax Expense.  Enogex’s consolidated income tax expense was approximately $20.3 million during the three months ended March 31, 2010 as compared to approximately $9.7 million during the same period in 2009, an increase of approximately $10.6 million, primarily due to higher pre-tax income during the three months ended March 31, 2010 as compared to the same period in 2009 and an adjustment for the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 7 of Condensed Consolidated Financial Statements).

Timing Items.   Enogex’s net income for the three months ended March 31, 2010 was approximately $27.4 million, which included a realized gain of approximately $1.5 million related to the March 2010 component of Enogex’s operational storage hedges. This amount will be offset by a realized loss of approximately $1.0 million upon recognition of the May 2010 component of Enogex’s operational storage hedges, which are currently deferred in Accumulated Other Comprehensive Income.

Enogex’s net income for the three months ended March 31, 2009 was approximately $15.4 million, which included a realized gain of approximately $3.3 million related to the March 2009 component of Enogex’s operational storage hedges. This amount was offset by a realized loss of approximately $1.5 million upon recognition of the May 2009 component of Enogex’s operational storage hedges.

OERI (Natural Gas Marketing)

	Three Months Ended
	March 31,
	2010		2009
(In millions)
Operating revenues	$	245.7	$	192.3
Cost of goods sold		244.3		187.8
Gross margin on revenues		1.4		4.5
Other operation and maintenance		2.7		2.6
Taxes other than income		0.2		0.2
Operating income (loss)	$	(1.5)	$	1.7

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Three Months Ended March 31, 2010 as Compared to Three Months Ended March 31, 2009

Operating Income

OERI’s operating loss was approximately $1.5 million during the three months ended March 31, 2010 as compared to operating income of approximately $1.7 million during the same period in 2009, a decrease in operating income of approximately $3.2 million, primarily due to a lower gross margin as discussed below.

Gross Margin

Gross margin was approximately $1.4 million during the three months ended March 31, 2010 as compared to approximately $4.5 million during the same period in 2009, a decrease in the gross margin of approximately $3.1 million, or 68.9 percent, primarily due to smaller differences in natural gas prices at various U.S. market locations which resulted in a reduced spread that OERI was able to realize from delivering gas under its transportation contracts, which decreased the gross margin from transportation by approximately $2.6 million.

Additional Information

Income Tax Expense (Benefit).  Income tax benefit was approximately $0.7 million during the three months ended March 31, 2010 as compared to income tax expense of approximately $0.6 million during the same period in 2009, a decrease in income tax expense of approximately $1.3 million, primarily due to lower pre-tax income during the three months ended March 31, 2010 as compared to the same period in 2009.

Non-GAAP Financial Measures

The Company has included in this Form 10-Q the non-GAAP financial measures Ongoing Earnings and Ongoing EPS.  The Company defines Ongoing Earnings as GAAP net income less the charge for the Medicare Part D tax subsidy and Ongoing EPS as GAAP EPS less the charge for the Medicare Part D tax subsidy.  The Medicare Part D tax subsidy represents a charge which management believes will not be recurring on a regular basis. Management believes that the presentation of Ongoing Earnings and Ongoing EPS provides useful information to investors, as it provides them an additional relevant comparison of the Company’s performance across periods.

The Company provides a reconciliation of Ongoing Earnings and Ongoing EPS to its most directly comparable financial measures as calculated and presented in accordance with GAAP.  The most directly comparable GAAP measure for Ongoing Earnings is GAAP net income which includes the impact of the charge for the Medicare Part D tax subsidy.  The most directly comparable GAAP measure for Ongoing EPS is GAAP EPS which includes the charge for the Medicare Part D tax subsidy. The non-GAAP financial measure of Ongoing Earnings and Ongoing EPS should not be considered as an alternative to GAAP net income attributable to the Company or GAAP EPS. Ongoing Earnings and Ongoing EPS are not a presentation made in accordance with GAAP and have important limitations as analytical tools.  They should not be considered in isolation or as a substitute for analysis of the Company’s results as reported under GAAP.  Because these non-GAAP financial measures exclude some, but not all, items that affect net income and EPS and is defined differently by different companies in the Company’s industry, the Company’s definition of Ongoing Earnings and Ongoing EPS may not be comparable to a similarly titled measure of other companies.

To compensate for the limitations of these non-GAAP financial measures as analytical tools, the Company believes it is important to review the comparable GAAP measures and understand the differences between the measures.

Reconciliation of Ongoing Earnings to GAAP Net Income for the Three Months Ended March 31, 2010 and 2009

(In millions)	Q1 2010 Ongoing Earnings		Medicare Part D Tax Subsidy		Q1 2010 GAAP Net Income		Q1 2009  GAAP and Ongoing Net Income (A)
OG&E	$	8.2	$	(7.0)	$	1.2	$	1.3
Enogex		29.4		(2.0)		27.4		15.4
Holding Company		(2.0)		(2.4)		(4.4)		0.1
Consolidated	$	35.6	$	(11.4)	$	24.2	$	16.8

(A) There were no one-time charges for the quarter ended March 31, 2009 therefore, ongoing and GAAP net income are the same.

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Reconciliation of Ongoing EPS to GAAP EPS for the Three Months Ended March 31, 2010 and 2009

(In millions)	Q1 2010 Ongoing EPS		Medicare Part D Tax Subsidy		Q1 2010 GAAP EPS		Q1 2009 GAAP and Ongoing EPS (B)
OG&E	$	0.08	$	(0.07)	$	0.01	$	0.01
Enogex		0.30		(0.02)		0.28		0.16
Holding Company		(0.02)		(0.02)		(0.04)		0.01
Consolidated	$	0.36	$	(0.11)	$	0.25	$	0.18

(B) There were no one-time charges for the quarter ended March 31, 2009 therefore, ongoing and GAAP EPS are the same.

Enogex has included in this Form 10-Q the non-GAAP financial measure EBITDA.  Enogex defines EBITDA as net income attributable to Enogex LLC before interest, income taxes and depreciation and amortization.  EBITDA is used as a supplemental financial measure by external users of the Company’s financial statements such as investors, commercial banks and others, to assess:

Ÿ   the financial performance of Enogex’s assets without regard to financing methods, capital structure or historical cost basis;

Ÿ   Enogex’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

Ÿ   the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Enogex provides a reconciliation of EBITDA to its most directly comparable financial measure as calculated and presented in accordance with GAAP.  The GAAP measure most directly comparable to EBITDA is net income attributable to Enogex LLC. The non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net income attributable to Enogex LLC. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool.   EBITDA should not be considered in isolation or as a substitute for analysis of Enogex’s results as reported under GAAP.  Because EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in Enogex’s industry, Enogex’s definition of EBITDA may not be comparable to a similarly titled measure of other companies.

To compensate for the limitations of EBITDA as an analytical tool, Enogex believes it is important to review the comparable GAAP measure and understand the differences between the measures.

Reconciliation of EBITDA to net income attributable to Enogex LLC

	Three Months Ended
	March 31,
(In millions)	2010		2009
Net income attributable to Enogex LLC	$	27.4	$	15.4
Add:
Interest expense, net		8.2		5.8
Income tax expense		20.3		9.7
Depreciation and amortization		17.8		14.8
EBITDA	$	73.7	$	45.7

Financial Condition

The balance of Cash and Cash Equivalents was approximately $5.7 million and $58.1 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $52.4 million, or 90.2 percent.  See “Cash Flows” for a discussion of the changes in Cash and Cash Equivalents.

The balance of Accounts Receivable was approximately $262.1 million and $291.4 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $29.3 million, or 10.1 percent, primarily due to a decrease in volumes and a slight decrease in natural gas prices at OERI, a decrease in OG&E’s billings to customers reflecting milder weather in March 2010 as compared to December 2009, a decrease in NGLs prices and the timing of customer payments received at Enogex.

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The balance of Income Taxes Receivable was approximately $76.0 million and $157.7 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $81.7 million, or 51.8 percent, primarily due to an income tax refund received in February 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repairs expense.

The balance of Fuel Inventories was approximately $129.3 million and $118.5 million at March 31, 2010 and December 31, 2009, respectively, an increase of approximately $10.8 million, or 9.1 percent, primarily due to a higher coal inventory balance due to higher average prices and ongoing maintenance at one of OG&E’s coal-fired power plants partially offset by a decrease in natural gas inventory at OERI resulting from a withdrawal of natural gas from storage at March 31, 2010.

The balance of Construction Work in Progress was approximately $188.0 million and $335.4 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $147.4 million, or 43.9 percent, primarily due to the costs associated with the Windspeed transmission line constructed by OG&E which was placed in service on March 31, 2010 being reclassified to Property, Plant and Equipment In Service partially offset by increased spending on various distribution, transmission and generation projects at OG&E.

The balance of Income Taxes Recoverable from Customers, Net was approximately $38.8 million and $19.1 million at March 31, 2010 and December 31, 2009, respectively, an increase of approximately $19.7 million, primarily due to a write-off of the deferred tax benefit associated with future Medicare Part D subsidy payments pursuant to the tax law changes in the Patient Protection and Affordable Care Act of 2009 and the Health Care and Education Reconciliation Act of 2010, which were signed into law in March 2010.

The balance of Short-Term Debt was approximately $341.6 million and $175.0 million at March 31, 2010 and December 31, 2009, respectively, an increase of approximately $166.6 million, or 95.2 percent, primarily due to an increase in commercial paper borrowings in the first quarter of 2010 to repay the remaining balance of Enogex’s $400.0 million 8.125% senior notes which matured on January 15, 2010.

The balance of Accounts Payable was approximately $242.0 million and $297.0 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $55.0 million, or 18.5 percent, primarily due to payments made in the first quarter of 2010 for projects accrued at December 31, 2009, the timing of outstanding checks clearing the bank and a decrease in natural gas volumes and a slight decrease in gas prices at OERI.

The balance of Accrued Interest was approximately $25.7 million and $60.6 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $34.9 million, or 57.6 percent, primarily due to timing of interest payments on long-term debt in the first quarter of 2010 partially offset by additional interest accrued on long-term debt in the first quarter of 2010.

The balance of Accrued Compensation was approximately $35.4 million and $50.1 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $14.7 million, or 29.3 percent, primarily due to the annual payment for incentive compensation made in the first quarter of 2010.

The balance of Long-Term Debt Due Within One Year was approximately $289.2 million at December 31, 2009 with no balance at March 31, 2010, due to the repayment of the remaining balance of Enogex’s $400.0 million 8.125% senior notes which matured on January 15, 2010.

The balance of Fuel Clause Over Recoveries was approximately $157.0 million and $187.5 million at March 31, 2010 and December 31, 2009, respectively, a decrease of approximately $30.5 million or 16.3 percent, primarily due to the fact that the amount billed to retail customers was lower than OG&E’s cost of fuel. The fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills.  As a result, OG&E under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel.  Provisions in the fuel clauses are intended to allow OG&E to amortize under and over recovery balances.

Off-Balance Sheet Arrangements

Except as discussed below, there have been no significant changes in the Company’s off-balance sheet arrangements from those discussed in the Company’s 2009 Form 10-K.

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OG&E Railcar Lease Agreement

At March 31, 2010, OG&E had a noncancellable operating lease with purchase options, covering 1,462 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.  At the end of the lease term, which is January 31, 2011, 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 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 approximately $31.5 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 now 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.

Liquidity and Capital Requirements

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities at OG&E and Enogex.  Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, delays in recovering unconditional fuel purchase obligations, fuel clause under and over recoveries and other general corporate purposes.  The Company generally meets its cash needs through a combination of cash generated from operations, short-term borrowings (through a combination of bank borrowings and commercial paper) and permanent financings.  See “Future Sources of Financing – Short-Term Debt” for information regarding the Company’s revolving credit agreements and commercial paper.

Net Available Liquidity

At March 31, 2010, the Company had approximately $5.7 million of cash and cash equivalents.  At March 31, 2010, the Company had approximately $768.9 million of net available liquidity under its revolving credit agreements.

Potential Collateral Requirements

Derivative instruments are utilized in managing the Company’s commodity price exposures and in OERI’s asset management, marketing and trading activities and hedging activities executed on behalf of the Company.  Agreements governing the derivative instruments may require the Company to provide collateral in the form of cash or a letter of credit in the event mark-to-market exposures exceed contractual thresholds or the Company’s credit ratings are lowered.  Future collateral requirements are uncertain, and are subject to terms of the specific agreements and to fluctuations in natural gas and NGLs market prices.

Cash Flows

	Three Months Ended
	March 31,
(In millions)	2010		2009
Net cash provided from operating activities	$	116.0	$	61.4
Net cash used in investing activities		(130.6)		(245.7)
Net cash (used in) provided from financing activities		(37.8)		156.3

The increase of approximately $54.6 million, or 88.9 percent, in net cash provided from operating activities during the three months ended March 31, 2010 as compared to the same period in 2009 was primarily due to:

Ÿ   an increase in cash receipts for sales at Enogex and OERI due to an increase in natural gas prices and NGLs prices and volumes in the first quarter of 2010 as compared to the same period in 2009;

Ÿ   an income tax refund received in February 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repairs expense;

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Ÿ   a cash collateral payment to counterparties of OERI related to OERI’s NGLs hedge positions in the first quarter of 2009; and

Ÿ   cash received in the first quarter of 2010 from the implementation of rate increases and riders at OG&E.

These increases in net cash provided from operating activities were partially offset by:

Ÿ   an increase in payments for purchases at Enogex and OERI due to an increase in natural gas prices and NGLs prices and volumes in the first quarter of 2010 as compared to the same period in 2009; and

Ÿ   higher fuel refunds at OG&E in the first quarter of 2010 as compared to the same period in 2009.

The decrease of approximately $115.1 million, or 46.8 percent, in net cash used in investing activities during the three months ended March 31, 2010 as compared to the same period in 2009 primarily related to higher levels of capital expenditures in 2009 related to OU Spirit and the Windspeed transmission line constructed by OG&E which was placed in service on March 31, 2010 and pipeline and processing projects at Enogex.

The decrease of approximately $194.1 million in net cash provided from financing activities during the three months ended March 31, 2010 as compared to the same period in 2009 was primarily due to:

Ÿ   repayment of the remaining balance of Enogex’s $400.0 million 8.125% senior notes which matured on January 15, 2010; and

Ÿ   a decrease in the issuance of common stock in the first quarter of 2010.

These decreases in net cash provided from financing activities were partially offset by:

Ÿ   an increase in short-term debt borrowings in the first quarter of 2010; and

Ÿ   an increase in borrowings under Enogex’s revolving credit agreement in the first quarter of 2010.

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Future Capital Requirements

Capital Expenditures

The Company’s consolidated estimates of capital expenditures are approximately:  2010 - $680 million, 2011 - $710 million, 2012 - $620 million, 2013 - $505 million, 2014 - $425 million and 2015 - $390 million.  These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company’s businesses) plus capital expenditures for known and committed projects (collectively referred to as the “Base Capital Expenditure Plan”).  Capital expenditures estimated for the next five years and beyond are as follows:

			Less than
			1 year		1-3 years		3-5 years		More than
(In millions)	Total		(2010)		(2011-2012)		(2013-2014)		5 years
OG&E Base Transmission	$	145	$	45	$	35	$	40	$	25
OG&E Base Distribution		1,360		230		455		450		225
OG&E Base Generation		220		45		70		70		35
OG&E Other		150		25		50		50		25
Total OG&E Base Transmission, Distribution,
Generation and Other		1,875		345		610		610		310
OG&E Known and Committed Projects:
Transmission Projects:
Sunnyside-Hugo (345 kV)		200		25		175		---		---
Sooner-Rose Hill (345 kV)		60		10		50		---		---
Windspeed (345 kV)		25		25		---		---		---
Balanced Portfolio 3E Projects		330		10		200		120		---
Total Transmission Projects		615		70		425		120		---
Other Projects:
Smart Grid Program (A)		230		40		120		60		10
System Hardening		35		20		15		---		---
OU Spirit		10		10		---		---		---
Other		35		15		20		---		---
Total Other Projects		310		85		155		60		10
Total OG&E Known and Committed Projects		925		155		580		180		10
Total OG&E (B)		2,800		500		1,190		790		320
Enogex (Base Maintenance and Known
and Committed Projects)		380		155		90		90		45
OGE Energy and OERI		150		25		50		50		25
Total capital expenditures	$	3,330	$	680	$	1,330	$	930	$	390

(A)  These capital expenditures are contingent upon OCC approval of OG&E’s Positive Energy Smart Grid Program and are net of the Smart Grid $130 million grant approved by the DOE.

(B) The Base Capital Expenditure Plan above excludes any environmental expenditures associated with Best Available Retrofit Technology (“BART”) requirements due to the uncertainty regarding BART costs.  As discussed in “– Environmental Laws and Regulations” below, pursuant to a proposed regional haze agreement OG&E has agreed to install low nitrogen oxide (“NOX”) burners and related equipment at the three affected generating stations.   Preliminary estimates indicate the cost will be approximately $100 million (plus or minus 30 percent).  For further information, see “– Environmental Laws and Regulations” below.

OG&E signed memoranda of understanding in February 2010 for approximately 197.8 MWs of wind turbine generators and certain related balance of plant engineering, procurement and construction services associated with Crossroads located in Dewey County, Oklahoma.  On April 8, 2010, OG&E filed an application with the OCC requesting pre-approval of this project and a rider to recover from Oklahoma customers the costs to construct Crossroads.  Crossroads is expected to cost approximately $397.6 million with a related annual revenue requirement of approximately $40.0 million, of which approximately $34.5 million is the Oklahoma jurisdictional portion. Capital expenditures related to the Crossroads project are not included in the table above because this project has not been approved by the OCC.  Additional capital expenditures beyond those identified in the table above, including additional incremental growth opportunities in electric transmission assets and at Enogex, will be evaluated based upon their impact upon achieving the Company’s financial objectives.  The

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capital expenditure projections related to Enogex in the table above reflect base market conditions at May 5, 2010 and do not reflect the potential opportunity for a set of growth projects that could materialize.

Pension Plan Funding

The Company previously disclosed in its 2009 Form 10-K that it may contribute up to $50 million to its pension plan during 2010.  In April 2010, the Company contributed approximately $20 million to its pension plan and currently expects to contribute an additional $30 million to its pension plan during the remainder of 2010.  Any remaining expected contributions to its pension plan during 2010 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.

Future Sources of Financing

Management expects that cash generated from operations, proceeds from the issuance of long and short-term debt and proceeds from the sales of common stock to the public through the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan or other offerings will be adequate over the next three years to meet anticipated cash needs and to fund future growth opportunities. The Company utilizes short-term borrowings (through a combination of bank borrowings and commercial paper) to satisfy temporary working capital needs and as an interim source of financing capital expenditures until permanent financing is arranged.

Short-Term Debt and Credit Facilities

Short-term borrowings generally are used to meet working capital requirements.  The Company borrows on a short-term basis, as necessary, by the issuance of commercial paper and by borrowings under its revolving credit agreements.  The short-term debt balance was approximately $341.6 million and $175.0 million at March 31, 2010 and December 31, 2009, respectively, and was comprised entirely of outstanding commercial paper borrowings at OGE Energy.  At March 31, 2010, Enogex had approximately $115.0 million in outstanding borrowings under its revolving credit agreement with no outstanding borrowings at December 31, 2009.  As Enogex’s credit agreement matures on March 31, 2013, borrowings thereunder are classified as long-term debt in the Company’s Condensed Consolidated Balance Sheets.  The following table provides information regarding the Company’s revolving credit agreements and available cash at March 31, 2010.

Revolving Credit Agreements and Available Cash (In millions)
	Aggregate		Amount		Weighted-Average
Entity	Commitment		Outstanding		Interest Rate	Maturity
OGE Energy	$	596.0	$	341.6	0.29%	December 6, 2012
OG&E		389.0		9.5	---%	December 6, 2012
Enogex		250.0		115.0	0.54%	March 31, 2013
		1,235.0		466.1	0.35%
Cash		5.7		N/A	N/A	N/A
Total	$	1,240.7	$	466.1	0.35%

OG&E has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any time for a two-year period beginning January 1, 2009 and ending December 31, 2010.  See Note 10 of Notes to the Condensed Consolidated Financial Statements for a discussion of the Company’s short-term debt activity.

Expected Issuance of OG&E Long-Term Debt

OG&E expects to issue between approximately $200 million and $300 million of long-term debt in mid-2010, depending on market conditions, to fund capital expenditures, repay short-term borrowings and for general corporate purposes.

Critical Accounting Policies and Estimates

The Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements contain information that is pertinent to Management’s Discussion and Analysis.  In preparing the Condensed Consolidated Financial Statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  Changes to these assumptions and estimates could have a material effect on the Company’s Condensed Consolidated Financial Statements.

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However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates.  In management’s opinion, the areas of the Company where the most significant judgment is exercised is in the valuation of pension plan assumptions, impairment estimates, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues for OG&E, operating revenues for Enogex, natural gas purchases for Enogex, the allowance for uncollectible accounts receivable and the valuation of purchase and sale contracts.  The selection, application and disclosure of the Company’s critical accounting estimates have been discussed with the Company’s Audit Committee and are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s 2009 Form 10-K.

Accounting Pronouncements

See Notes to Condensed Consolidated Financial Statements for a discussion of accounting pronouncements that are applicable to the Company.

Commitments and Contingencies

Except as disclosed otherwise in this Form 10-Q and the Company’s 2009 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.  See Notes 13 and 14 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q and Notes 13 and 14 of Notes to Consolidated Financial Statements and Item 3 of Part I of the 2009 Form 10-K for a discussion of the Company’s commitments and contingencies.

Environmental Laws and Regulations

The activities of OG&E and Enogex are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection including the discharge of materials into the environment. These laws and regulations can restrict or impact OG&E’s and Enogex’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. These environmental laws and regulations are discussed in detail in Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Company’s 2009 Form 10-K.  Except as set forth below, there have been no material changes to such items.

Air

RICE MACT Amendments

On March 5, 2009, the U.S. Environmental Protection Agency (“EPA”) initiated rulemaking concerning new national emission standards for hazardous air pollutants for existing reciprocating internal combustion engines by proposing amendments to the National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engine Maximum Achievable Control Technology (“proposed RICE MACT Amendments”).  On March 3, 2010, the EPA published final rules on a portion of its original proposed amendments and established national emission standards for hazardous air pollutants for three types of compression ignition reciprocating internal combustion engines (“2010 CI RICE MACT Amendments”).  The 2010 CI RICE MACT Amendments were effective May 3, 2010 and are expected to have an insignificant impact to the Company.  The remaining provisions of the proposed RICE MACT Amendments are still under review by the EPA and the EPA has stated that it anticipates that it will finalize its requirements for existing stationary spark ignition engines by August 2010.  The costs that may be incurred to comply with these remaining proposed regulations, including the testing and modification of the spark ignition engines, are uncertain at this time. The current proposed compliance deadline is three years from the effective date of the enacted and proposed rules.

Regional Haze

On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule.  These regulations are intended to protect visibility in national parks and wilderness areas (“Class I areas”) throughout the United States.  In Oklahoma, the Wichita Mountains are the only area covered under the regulation.  However, Oklahoma’s impact on parks in other states must also be evaluated.  Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to the degradation of visibility.  The state of Oklahoma joined with eight other central states to address these visibility impacts.

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OG&E was required to evaluate the installation of BART to address regional haze at sources built between 1962 and 1977.  The Oklahoma Department of Environmental Quality (“ODEQ”) made a preliminary determination to accept an application for a waiver from BART requirements for the Horseshoe Lake generating station based on modeling showing no significant impact on visibility in nearby Class I areas.  The Horseshoe Lake waiver was included in the ODEQ regional haze state implementation plan (“SIP”) submitted to the EPA on February 18, 2010.

Waivers were not available for the BART-eligible units at the Seminole, Muskogee and Sooner generating stations.  OG&E submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of NOX controls on all three units.  On May 30, 2008, OG&E filed BART evaluations for the affected generating units at the Muskogee and Sooner generating stations.  In this filing, OG&E indicated its intention to install low NOX combustion technology at its affected generating stations and to continue to burn low sulfur coal at the four coal-fired generating units at its Muskogee and Sooner generating stations.  OG&E did not propose the installation of scrubbers at these four coal-fired generating units because OG&E concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of more than $1.0 billion) would not be cost-effective.  The ODEQ published a draft SIP for public review on November 13, 2009.  This draft SIP suggested that scrubbers would be needed to comply with the regional haze regulations, but noted OG&E’s cost-effectiveness analysis.  Following negotiations with the ODEQ, in February 2010 OG&E and the ODEQ entered into an Agreement (“Agreement”) which specifies that BART for reducing NOX emissions at all seven BART-eligible units at the Seminole, Muskogee and Sooner generating stations should be the installation of low NOX burners with overfire air (and flue gas recirculation on two of the affected units) and accompanying emission rate and annual emission tonnage limits.  Preliminary estimates based on recent industry experience and cost projections estimate the total cost of the NOX-related equipment at the three affected generating stations at approximately $100 million (plus or minus 30 percent).  After OG&E obtains estimates from vendors based on a detailed engineering design, it will have a more firm estimate of the exact cost of the NOX-related equipment subject to changes in the cost of basic materials.  Under the Agreement, the specified BART for reducing sulfur dioxide (“SO2”) at the four coal-fired units at the Muskogee and Sooner generating stations would be continued use of low sulfur coal and emission rate and annual emission tonnage limits consistent with such use of low sulfur coal.  Implementation of these BART requirements would be achieved within five years of the EPA’s approval of Oklahoma’s regional haze SIP.

Under the Agreement, there also would be an alternative compliance obligation in the event that the EPA disapproves the aforementioned BART determination and the underlying conclusion that dry flue gas desulfurization units with Spray Dryer Absorber (“Dry Scrubbers”) are not cost-effective.  In such an event, and only after OG&E has exhausted all judicial and administrative appeals of the EPA disapproval, OG&E would have two options.  First, OG&E could choose to install Dry Scrubbers (or meet the corresponding SO2 emissions limits associated with Dry Scrubbers) by January 1, 2018.  Second, OG&E could choose to comply with the regional haze regulations by implementing a fuel switching alternative.  This alternative would require OG&E to achieve a combined annual SO2 emission limit by December 31, 2026 that is equivalent to: (i) the SO2 emission limits associated with installing and operating Dry Scrubbers on two of the BART-eligible coal fired units and (ii) being at or below the SO2 emissions that would result from switching the other two coal-fired units to natural gas.  If OG&E has elected to comply with this alternative and if, prior to January 1, 2022, any of these units is required by any environmental law other than the regional haze rule to install flue gas desulfurization equipment or achieve an SO2 emissions rate lower than 0.10 lbs/ Million British thermal unit, and if OG&E proceeds to take all necessary steps to comply with such legal requirement, the enforceable emission limits in the operating permits for the affected coal units would be adjusted to reflect the installation of that equipment or the emission rates specified under such legal requirement and OG&E would no longer be required to undertake the 2026 emission levels.

The ODEQ included the Agreement in its regional haze SIP that it submitted to the EPA on February 18, 2010. It is anticipated that the EPA will take final action on the SIP for regional haze during the first quarter of 2011. OG&E cannot predict what action the EPA will take.

Until the EPA takes final action on the regional haze SIP, the total cost of compliance, including capital expenditures, cannot be estimated by OG&E with a reasonable degree of certainty.  OG&E expects that any necessary expenditures for the installation of emission control equipment will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from OG&E’s retail customers under House Bill 1910, which was enacted into law in May 2005.

Climate Change

On April 1, 2010, the EPA and the U.S. Department of Transportation’s National Highway Traffic Safety Administration issued a joint rule to establish new greenhouse gas emissions regulations that affect tailpipe standards for model years 2012 – 2016 light-duty vehicles.  This rule makes greenhouse gas emissions subject to regulation under the

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Federal Clean Air Act for stationary sources as well as for mobile sources.  As a result, OG&E’s facilities may be required to include greenhouse gas emission limits in permits issued pursuant to the Federal Clean Air Act.  On April 2, 2010, the EPA issued an interpretation stating that the Federal Clean Air Act permit requirements would not apply to stationary sources prior to January 2, 2011.  The EPA has stated that the Federal Clean Air Act permit requirements may be phased in starting on that date.  The details of when the requirements will apply to particular stationary sources are not currently known.

Coal Ash

As previously reported in the Company’s 2009 Form 10-K, the EPA had announced that it was considering regulation of coal ash.  On May 4, 2010, the EPA issued a proposed rule that includes several options for regulating coal ash.  The Company is studying the proposal and its possible impacts on operations.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

Except as set forth below, the market risks set forth in Part II, Item 7A of the Company’s 2009 Form 10-K appropriately represent, in all material respects, the market risks affecting the Company.

Commodity Price Risk

The market risks inherent in the Company’s market risk sensitive instruments, positions and anticipated commodity transactions are the potential losses in value arising from adverse changes in the commodity prices to which the Company is exposed.  These market risks can be classified as trading, which includes transactions that are entered into voluntarily to capture subsequent changes in commodity prices, or non-trading, which includes the exposure some of the Company’s assets have to commodity prices.

Trading Activities

The trading activities of OERI are conducted throughout the year subject to daily and monthly trading stop loss limits set by the Risk Oversight Committee.  Those trading stop loss limits currently are $2.5 million.  The daily loss exposure from trading activities is measured primarily using value-at-risk (“VaR”), which estimates the potential losses the trading activities could incur over a specified time horizon and confidence level.  Currently, the Company utilizes the variance/co-variance method for calculating VaR.  The VaR limit set by the Risk Oversight Committee for the Company’s trading activities, assuming a 95 percent confidence level, currently is $1.5 million.  These limits are designed to mitigate the possibility of trading activities having a material adverse effect on the Company’s operating income.

A sensitivity analysis has been prepared to estimate the Company’s exposure to market risk created by trading activities.  The value of trading positions is a summation of the fair values calculated for each net commodity position based upon quoted market prices.  Market risk is estimated as the potential loss in fair value resulting from a hypothetical 20 percent adverse change in quoted market prices.  The result of this analysis, which may differ from actual results, is as follows at:

March 31 (In millions)	2010		2009
Commodity market risk, net	$	0.2	$	0.6

Non-Trading Activities

The prices of natural gas and NGLsand NGLs processing spreads are subject to fluctuations resulting from changes in supply and demand.  The changes in these prices have a direct effect on the compensation the Company receives for operating some of its assets.  To partially reduce non-trading commodity price risk, the Company utilizes risk mitigation tools such as default processing fees and ethane rejection capabilities to protect its downside exposure while maintaining its upside potential.  Additionally, the Company hedges, through the utilization of derivatives and other forward transactions, the effects these market fluctuations have on the Company’s operating income.  Because the commodities covered by these hedges are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.

Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts.  Normal purchases and normal sales contracts are not recorded in Price Risk Management 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

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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.

A sensitivity analysis has been prepared to estimate the Company’s exposure to the market risk of the Company’s non-trading activities. The Company’s daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts, financial and commodity derivative instruments and anticipated natural gas processing spreads and fuel recoveries.  Quoted market prices are not available for all of the Company’s non-trading positions; therefore, the value of non-trading positions is a summation of the forecasted values calculated for each commodity based upon internally generated forward price curves.  Market risk is estimated as the potential loss in fair value resulting from a hypothetical 20 percent adverse change in such prices over the next 12 months.  The result of this analysis, which may differ from actual results, is as follows at:

March 31 (In millions)	2010		2009
Commodity market risk, net	$	19.4	$	6.2

The increase in downside commodity market risk reflected in the table above is primarily due to favorable commodity price conditions at March 31, 2010 as compared to March 31, 2009.  These favorable conditions increased the Company’s per unit exposure.  During 2009, the Company reduced its volumetric exposure to commodity market risk by converting a portion of its agreements from commodity market based compensation to fixed-fee based compensation.  Absent these conversions, the commodity market risk at March 31, 2010 would have been even greater.

Item 4.  Controls and Procedures.

The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (“CEO”) and chief financial officer (“CFO”), allowing timely decisions regarding required disclosure.  As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company’s management, including the CEO and CFO, of the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.

No change in the Company’s internal control over financial reporting has occurred during the Company’s most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934).

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

Reference is made to Part I, Item 3 of the Company’s 2009 Form 10-K for a description of certain legal proceedings presently pending.  Except as set forth below and in Notes 13 and 14 of Notes to Condensed Consolidated Financial Statements in this Form 10-Q, there are no new significant cases to report against the Company or its subsidiaries and there have been no material changes in the previously reported proceedings.

1.           Hull v. Enogex LLC.On November 14, 2008, a natural gas gathering pipeline owned by Enogex ruptured in Grady County, near Alex, Oklahoma, resulting in a fire that caused injuries to one resident and destroyed three residential structures.  After the incident, Enogex coordinated and assisted the affected residents.  Enogex resolved matters with two of the residents and Enogex continued to seek resolution with a remaining resident.  This resident filed a legal action in May 2009 in the District Court of Cleveland County, Oklahoma, against OGE Energy and Enogex.  This matter was resolved by the parties on April 8, 2010.  The ultimate resolution of this incident was not material to the Company in light of previously established reserves and insurance coverage.

2.           Oxley Litigation. OG&E has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma.  This case has been pending for more than 11 years.  The plaintiffs alleged that OG&E breached the terms of contracts covering several wells by failing to purchase gas from the plaintiffs in amounts set forth in

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the contracts.  The plaintiff’s most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages  (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, OG&E agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, OG&E will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. The arbitration hearing was completed recently and the final briefs were provided to the arbitration panel on March 17, 2010.  A ruling by the panel is expected in the second quarter of 2010.  While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, OG&E believes that this lawsuit will not have a material adverse effect on the Company’s consolidated financial position or results of operations.

3.           Franchise Fee Lawsuit.  On June 19, 2006, two OG&E customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on OG&E’s electric bills.  The plaintiffs claim that OG&E improperly charged sales tax based on franchise fee charges paid by its customers.  The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law.  OG&E’s motion for summary judgment was denied by the trial judge.  OG&E filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit.  In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC.   In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes OG&E to collect the challenged franchise fee charges.  On March 10, 2009, the Oklahoma Attorney General, OG&E, OG&E Shareholders Association and the Staff of the Public Utility Division of the OCC all filed briefs arguing that the application should be dismissed.  On December 9, 2009 the OCC issued an order dismissing the plaintiffs’ request for a modification of the 1994 OCC order which authorized OG&E to collect and remit sales tax on franchise fee charges. In its December 9, 2009 order, the OCC advised the plaintiffs that the ruling does not address the question of whether OG&E’s collection and remittance of such sales tax should be discontinued prospectively. On December 21, 2009, the plaintiffs filed a motion at the Oklahoma Supreme Court asking the court to deny OG&E’s writ of prohibition and to remand the cause to the District Court. On December 29, 2009, the Oklahoma Supreme Court declared the plaintiffs’ motion moot. On January 27, 2010, the OCC Staff filed a motion asking the OCC to dismiss the cause and close the cause at the OCC.  On April 19, 2010, the OCC issued a final order dismissing with prejudice the applicants’ claims for recovery of previously paid taxes on franchise fees and approving the closing of this matter.

4.           Will Price, et al. v. El Paso Natural Gas Co., et al. (Price I).  On September 24, 1999, various subsidiaries of the Company were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands.  On April 10, 2003, the court entered an order denying class certification.  On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003.  In its amended petition (the “Fourth Amended Petition”), OG&E and Enogex Inc. were omitted from the case but two of the Company’s other subsidiary entities remained as defendants.  The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of the Company’s subsidiary entities, have improperly measured the volume of natural gas.  The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment.  In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion.  The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest.  The plaintiffs also reserved the right to seek punitive damages.

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues.  A hearing on class certification issues was held April 1, 2005.  In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action.  The court has not yet ruled on the motion to intervene.

The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007.  On September 18, 2009, the court entered its order denying class certification.  On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.

The Company intends to vigorously defend this action.  At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

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5.           Will Price, et al. v. El Paso Natural Gas Co., et al. (Price II).  On May 12, 2003, the plaintiffs (same as those in the Fourth Amended Petition in Price I above) filed a new class action petition in the District Court of Stevens County, Kansas naming the same defendants and asserting substantially identical legal and/or equitable theories as in the Fourth Amended Petition of the Price I case.  OG&E and Enogex Inc. were not named in this case, but two subsidiary entities of the Company were named in this case.  The plaintiffs allege that the defendants mismeasured the Btu content of natural gas obtained from or measured for the plaintiffs.  In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion.  The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest.  The plaintiffs also reserved the right to seek punitive damages.

Discovery was conducted on the class certification issues, and the parties fully briefed these same issues.  A hearing on class certification issues was held April 1, 2005.  In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action.  The court has not yet ruled on the motion to intervene.

The class certification issues were briefed and argued by the parties in 2005 and proposed findings of facts and conclusions of law on class certification were filed in 2007.  On September 18, 2009, the court entered its order denying class certification.  On October 2, 2009, the plaintiffs filed for a rehearing of the court’s denial of class certification. On February 10, 2010 the court heard arguments on the rehearing request and by an order dated March 31, 2010, the court denied the plaintiffs’ request for rehearing.

The Company intends to vigorously defend this action.  At this time, the Company is unable to provide an evaluation of the likelihood of an unfavorable outcome and an estimate of the amount or range of potential loss to the Company.

Item 1A.  Risk Factors.

There have been no significant changes in the Company’s risk factors from those discussed in the Company’s 2009 Form 10-K, which are incorporated herein by reference.

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

The shares indicated below represent shares of Company common stock purchased on the open market by the trustee for the Company’s qualified defined contribution retirement plan and reflect shares purchased with employee contributions as well as the portion attributable to the Company’s matching contributions.

						Approximate Dollar
					Total Number of	Value of Shares that
					Shares Purchased as	May Yet Be
	Total Number of		Average Price Paid		Part of Publicly	Purchased Under the
Period	Shares Purchased		per Share		Announced Plan	Plan
1/1/10 – 1/31/10		69,300	$	36.96	N/A	N/A
2/1/10 – 2/28/10		96,500	$	36.16	N/A	N/A
3/1/10 – 3/31/10		46,300	$	36.43	N/A	N/A

N/A – not applicable

Item 6.  Exhibits.

Exhibit No.               Description

3.01 OGE Energy Corp. Amended By-laws dated February 17, 2010. (Filed as Exhibit 3.01 to OGE Energy’s Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein)

10.01 Agreement, dated February 17, 2010, between Oklahoma Gas and Electric Company and Oklahoma Department of Environmental Quality. (Filed as Exhibit 99.01 to OGE Energy’s Form 8-K filed February 23, 2010 (File No. 1-12579) and incorporated by reference herein)

10.02 Form of Performance Unit Agreement under the Company’s 2008 Stock Incentive Plan.

31.01 Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01 Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE

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

	OGE ENERGY CORP.
	(Registrant)
By	/s/ Scott Forbes
	Scott Forbes
	Controller and Chief Accounting Officer

May 6, 2010

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