OKLAHOMA GAS & ELECTRIC CO - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - OKLAHOMA GAS & ELECTRIC CO	Financial_Report.xls
EX-32.01 - OG&E 1ST QTR 2011 10-Q EXHIBIT 32.01 - OKLAHOMA GAS & ELECTRIC CO	ogande1stqtr11ex3201.htm
EX-31.01 - OG&E 1ST QTR 2011 10-Q EXHIBIT 31.01 - OKLAHOMA GAS & ELECTRIC CO	ogande1stqtr11ex3101.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

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

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number: 1-1097

Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format permitted by General Instruction H(2).

OKLAHOMA GAS AND ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

Oklahoma		73-0382390
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

405-553-3000

(Registrant’s telephone number, including area code)

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

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

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

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

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

Yes o No þ

At March 31, 2011, there were 40,378,745 shares of common stock, par value $2.50 per share, outstanding, all of which were held by OGE Energy Corp. There were no other shares of capital stock of the registrant outstanding at such date.

OKLAHOMA GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2011

TABLE OF CONTENTS

		Page

GLOSSARY OF TERMS		ii

FORWARD-LOOKING STATEMENTS		1


Part I – FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Condensed Statements of Income		2
Condensed Statements of Cash Flows		3
Condensed Balance Sheets		4
Condensed Statements of Changes in Stockholder’s Equity		6
Condensed Statements of Comprehensive Income		6
Notes to Condensed Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3 . Quantitative and Qualitative Disclosures About Market Risk		26

Item 4. Controls and Procedures		26


Part II – OTHER INFORMATION

Item 1. Legal Proceedings		26

Item 1A. Risk Factors		26

Item 6. Exhibits		27

Signature		28

GLOSSARY OF TERMS

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

Abbreviation	Definition
2010 Form 10-K	Annual Report on Form 10-K for the year ended December 31, 2010
AEFUDC	Allowance for equity funds used during construction
APSC	Arkansas Public Service Commission
BART	Best Available Retrofit Technology
Company	Oklahoma Gas and Electric Company, wholly-owned subsidiary of OGE Energy
Crossroads	Company’s Crossroads wind project in Dewey County, Oklahoma
DRIP/DSPP	Automatic Dividend Reinvestment and Stock Purchase Plan
Dry Scrubbers	Dry flue gas desulfurization units with Spray Dryer Absorber
EHV	Extra High Voltage
Enogex	Enogex Holdings LLC, collectively with its subsidiaries, a majority-owned subsidiary of OGE Energy
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States
GFB	Guaranteed Flat Bill
GCELC	Gulf Coast Environmental Labor Coalition
kV	Kilovolt
MMBtu	Million British thermal unit
Moody’s	Moody’s Investors Services
MW	Megawatt
NOX	Nitrogen oxide
NYMEX	New York Mercantile Exchange
OCC	Oklahoma Corporation Commission
ODEQ	Oklahoma Department of Environmental Quality
OER	OGE Energy Resources LLC, wholly-owned subsidiary of Enogex LLC
Off-system sales	Sales to other utilities and power marketers
OMPA	Oklahoma Municipal Power Authority
Pension Plan	Qualified defined benefit retirement plan
PRM	Price risk management
SEC	Securities and Exchange Commission
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool
System sales	Sales to the Company’s customers
Windspeed	Company’s transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” in the Company’s 2010 Form 10-K and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

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

the ability of the Company and OGE Energy to access the capital markets and obtain financing on favorable terms;

prices and availability of electricity, coal and natural gas;

business conditions in the energy industry;

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

unusual weather;

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

Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets;

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

changes in accounting standards, rules or guidelines;

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

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

advances in technology;

creditworthiness of suppliers, customers and other contractual parties; and

other risk factors listed in the reports filed by the Company with the SEC including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to the Company’s 2010 Form 10-K.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.


OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

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

OPERATING REVENUES	$	422.1	$	444.0

COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)		219.4		250.8
Gross margin on revenues		202.7		193.2

OPERATING EXPENSES
Other operation and maintenance		105.8		93.9
Depreciation and amortization		51.8		49.7
Taxes other than income		19.1		17.7
Total operating expenses		176.7		161.3

OPERATING INCOME		26.0		31.9

OTHER INCOME (EXPENSE)
Interest income		0.1		---
Allowance for equity funds used during construction		4.4		2.3
Other income		5.0		2.5
Other expense		(0.6)		(0.6)
Net other income		8.9		4.2

INTEREST EXPENSE
Interest on long-term debt		27.8		24.1
Allowance for borrowed funds used during construction		(2.3)		(1.2)
Interest on short-term debt and other interest charges		0.6		1.3
Interest expense		26.1		24.2

INCOME BEFORE TAXES		8.8		11.9

INCOME TAX EXPENSE		2.4		10.7

NET INCOME	$	6.4	$	1.2

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

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

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	6.4	$	1.2
Adjustments to reconcile net income to net cash provided from
operating activities
Depreciation and amortization		51.8		49.7
Deferred income taxes and investment tax credits, net		2.4		11.5
Allowance for equity funds used during construction		(4.4)		(2.3)
Stock-based compensation expense		0.9		---
Regulatory assets		6.0		4.2
Regulatory liabilities		2.8		(2.2)
Other assets		1.5		(0.4)
Other liabilities		(4.1)		(2.7)
Change in certain current assets and liabilities
Accounts receivable, net		3.2		10.9
Accrued unbilled revenues		6.3		10.9
Fuel, materials and supplies inventories		4.4		(18.7)
Gas imbalance assets		0.1		---
Fuel clause under recoveries		0.6		(0.6)
Other current assets		5.8		1.1
Accounts payable		(25.5)		(1.9)
Accounts payable - affiliates		(1.2)		(2.3)
Income taxes payable - parent		---		87.8
Gas imbalance liabilities		0.1		---
Fuel clause over recoveries		(4.5)		(30.5)
Other current liabilities		(18.2)		(37.3)
Net Cash Provided from Operating Activities		34.4		78.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(127.0)		(99.6)
Reimbursement of capital expenditures		11.3		---
Other investing activities		0.4		0.2
Net Cash Used in Investing Activities		(115.3)		(99.4)
CASH FLOWS FROM FINANCING ACTIVITIES
Changes in advances with parent		80.9		21.0
Net Cash Provided from Financing Activities		80.9		21.0
NET CHANGE IN CASH AND CASH EQUIVALENTS		---		---
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		---		---
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	---	$	---

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS

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

ASSETS
CURRENT ASSETS
Accounts receivable, less reserve of $1.2 and $1.6, respectively	$	139.1	$	142.3
Accrued unbilled revenues		50.5		56.8
Advances to parent		---		68.9
Fuel inventories		127.2		134.9
Materials and supplies, at average cost		80.4		77.1
Gas imbalances		---		0.1
Deferred income taxes		10.8		10.7
Fuel clause under recoveries		0.4		1.0
Other		14.6		20.4
Total current assets		423.0		512.2

OTHER PROPERTY AND INVESTMENTS, at cost		2.8		2.9

PROPERTY, PLANT AND EQUIPMENT
In service		7,082.1		7,043.6
Construction work in progress		410.8		328.1
Total property, plant and equipment		7,492.9		7,371.7
Less accumulated depreciation		2,520.8		2,494.4
Net property, plant and equipment		4,972.1		4,877.3

DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets		412.1		489.4
Other		16.2		16.3
Total deferred charges and other assets		428.3		505.7

TOTAL ASSETS	$	5,826.2	$	5,898.1

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (Continued)

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

LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates	$	3.2	$	4.4
Accounts payable - other		138.1		144.1
Advances from parent		12.0		---
Customer deposits		63.9		63.2
Accrued taxes		18.7		31.2
Accrued interest		25.1		41.6
Accrued compensation		20.5		22.2
Price risk management		1.2		1.3
Gas imbalances		0.1		---
Fuel clause over recoveries		25.4		29.9
Other		52.1		40.3
Total current liabilities		360.3		378.2

LONG-TERM DEBT		1,790.5		1,790.4

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		185.7		259.8
Deferred income taxes		1,056.4		1,055.3
Deferred investment tax credits		8.5		9.4
Regulatory liabilities		205.6		193.1
Price risk management		1.9		2.2
Other		31.6		31.6
Total deferred credits and other liabilities		1,489.7		1,551.4

Total liabilities		3,640.5		3,720.0

COMMITMENTS AND CONTINGENCIES (NOTE 10)

STOCKHOLDER’S EQUITY
Common stockholder’s equity		959.4		958.4
Retained earnings		1,228.2		1,221.8
Accumulated other comprehensive loss, net of tax		(1.9)		(2.1)
Total stockholder’s equity		2,185.7		2,178.1

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	5,826.2	$	5,898.1

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

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY
(Unaudited)
(In millions)	Common Stock		Premium on Common Stock		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total
Balance at December 31, 2010	$	100.9	$	857.5	$	1,221.8	$	(2.1)	$	2,178.1
Comprehensive income
Net income		---		---		6.4		---		6.4
Other comprehensive income, net of tax		---		---		---		0.2		0.2
Comprehensive income		---		---		6.4		0.2		6.6
Stock-based compensation		---		1.0		---		---		1.0
Balance at March 31, 2011	$	100.9	$	858.5	$	1,228.2	$	(1.9)	$	2,185.7

Balance at December 31, 2009	$	100.9	$	857.5	$	1,066.3	$	(0.4)	$	2,024.3
Comprehensive income (loss)
Net income		---		---		1.2		---		1.2
Other comprehensive loss, net of tax		---		---		---		(1.2)		(1.2)
Comprehensive income (loss)		---		---		1.2		(1.2)		---
Balance at March 31, 2010	$	100.9	$	857.5	$	1,067.5	$	(1.6)	$	2,024.3

OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended
	March 31,
(In millions)	2011		2010
Net income	$	6.4	$	1.2
Other comprehensive income, net of tax
Deferred commodity contracts hedging gains (losses), net of tax of $0.1 million and ($0.9) million, respectively		0.2		(1.2)
Other comprehensive income (loss), net of tax		0.2		(1.2)
Total comprehensive income	$	6.6	$	---

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

OKLAHOMA GAS AND ELECTRIC COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

1.	Summary of Significant Accounting Policies

Organization

The Company generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. The Company’s operations are subject to regulation by the OCC, the APSC and the FERC. The Company is a wholly-owned subsidiary of OGE Energy which 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 was incorporated in 1902 under the laws of the Oklahoma Territory. The Company is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Basis of Presentation

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

In the opinion of management, all adjustments necessary to fairly present the financial position of the Company at March 31, 2011 and December 31, 2010, the results of its operations for the three months ended March 31, 2011 and 2010 and the results of its cash flows for the three months ended March 31, 2011 and 2010, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011 or for any future period. The Condensed Financial Statements and Notes thereto should be read in conjunction with the audited Financial Statements and Notes thereto included in the Company’s 2010 Form 10-K.

Accounting Records

The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, the Company, 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.

The Company 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 the Company’s regulatory assets and liabilities at:

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

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

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

Non-Current
Accrued removal obligations, net		$	192.3	$	184.9
Deferred Pension Plan expenses			10.7		8.2
Other			2.6		---
Total Non-Current Regulatory Liabilities		$	205.6	$	193.1
(A)	Included in Other Current Assets on the Condensed Balance Sheets.
(B)	Included in Other Current Liabilities on the Condensed Balance Sheets.

Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If the Company were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of which could be significant.

Related Party Transactions

OGE Energy charged operating costs to the Company of $31.0 million and $23.5 million during the three months ended March 31, 2011 and 2010, respectively. OGE Energy 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, either as overhead based primarily on labor costs or using the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses.

During each of the three months ended March 31, 2011 and 2010, the Company recorded an expense from its affiliate, Enogex, of $8.7 million for transporting gas to the Company’s natural gas-fired generating facilities. During each of the three months ended March 31, 2011 and 2010, the Company recorded an expense from Enogex of $3.2 million for natural gas storage services. During the three months ended March 31, 2011 and 2010, the Company also recorded natural gas purchases from Enogex, through its subsidiary, OER, of $12.6 million and $14.3 million, respectively. There are $3.3 million and $4.3 million of natural gas purchases recorded at March 31, 2011 and December 31, 2010, respectively, which are included in Accounts Payable – Affiliates in the Condensed Balance Sheets for these activities.

On July 1, 2009, the Company, Enogex and OER entered into hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at the Company resulting from the cost of generation associated with a wholesale power sales contract with the OMPA. Enogex sold physical natural gas to OER, and the Company entered into an offsetting natural gas swap with OER. These transactions are for 50,000 MMBtu per month from August 2009 to December 2013 (see Note 3 for a further discussion).

During each of the three months ended March 31, 2011 and 2010, the Company recorded interest income of less than $0.1 million for advances made to OGE Energy from the Company.

During each of the three months ended March 31, 2011 and 2010, the Company recorded interest expense of less than $0.1 million for advances made by OGE Energy to the Company. The interest rate charged on advances to the Company from OGE Energy approximates OGE Energy’s commercial paper rate.

Reclassifications

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

2.	Fair Value Measurements

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

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

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. Instruments classified as Level 2 include hedging transactions to offset natural gas long positions at Enogex with short natural gas exposures at the Company resulting from the cost of generation associated with a wholesale power sales contract with the OMPA.

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

The Company utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk.

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

At March 31, 2011 and December 31, 2010, the Company had no gross derivative assets measured at fair value on a recurring basis. At March 31, 2011 and December 31, 2010, the Company had $3.1 million and $3.5 million, respectively, of gross derivative liabilities measured at fair value on a recurring basis which are considered level 2 in the fair value hierarchy.

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

	March 31, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
(In millions)	Amount		Value		Amount		Value
Price Risk Management Liabilities
Energy Derivative Contracts	$	3.1	$	3.1	$	3.5	$	3.5

Long-Term Debt
Senior Notes	$	1,655.1	$	1,810.4	$	1,655.0	$	1,831.5
Industrial Authority Bonds		135.4		135.4		135.4		135.4

The carrying value of the financial instruments on the Condensed Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s energy derivative contracts was determined generally based on quoted market prices. The valuation of instruments also considers the credit risk of the counterparties. The fair value of the Company’s long-term debt is based on quoted market prices and estimates of current rates available for similar issues with similar maturities.

3.	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 occasionally uses commodity price swap contracts to manage the Company’s commodity price risk exposures. Natural gas swaps are used to manage the Company’s natural gas exposure associated with a wholesale generation sales contract.

Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed 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) electric power contracts by the Company and (ii) fuel procurement by the Company.

The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement.

Interest Rate Risk

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

Credit Risk

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

Cash Flow Hedges

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

At March 31, 2011 and December 31, 2010, the Company had no derivative instruments that were designated as cash flow hedges.

Fair Value Hedges

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

At March 31, 2011 and December 31, 2010, the Company had no derivative instruments that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

At March 31, 2011 and December 31, 2010, the Company had no material derivative instruments that were not designated as hedging instruments.

Credit-Risk Related Contingent Features in Derivative Instruments

At March 31, 2011, the Company had no derivative instruments that contain credit-risk related contingent features.

4.	Stock-Based Compensation

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

	Three Months Ended March 31,
(In millions)	2011		2010
Performance units
Total shareholder return	$	0.4	$	0.3
EPS		0.5		0.1
Total performance units		0.9		0.4
Restricted stock		---		0.1
Total compensation expense	$	0.9	$	0.5
Income tax benefit	$	0.4	$	0.2

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

		Units/Shares Related to OGE Energy		Units/Shares Related to the Company		Fair Value
Grants
Performance units (Total shareholder return)			213,721		43,302	$	46.09
Performance units (EPS)			71,238		14,431	$	41.61
Restricted stock			2,855		1,713	$	46.18
Conversions
Performance units (A)			218,425		41,141		N/A
(A)	Performance units were converted based on a payout ratio of 178.4 percent of the target number of performance units granted in February 2008 and are included in the 267,876 shares of new common stock issued during the three months ended March 31, 2011 as discussed below.

OGE Energy issues new shares to satisfy stock option exercises, restricted stock grants and payouts of earned performance units. During the three months ended March 31, 2011, there were 267,876 shares of new common stock issued pursuant to OGE Energy’s stock incentive plans related to exercised stock options, restricted stock grants and payouts of earned performance units, of which 53,780 shares related to the Company’s employees.

5.	Accumulated Other Comprehensive Loss

The balance of Accumulated Other Comprehensive Loss was $1.9 million and $2.1 million at March 31, 2011 and December 31, 2010, respectively, related to deferred commodity contracts hedging activity.

6.	Income Taxes

The Company is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal tax examinations by tax authorities for years prior to 2007 or state and local tax examinations by tax authorities for years prior to 2002. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its Federal investment tax credits on a ratable basis throughout the year. The Company earns both Federal and Oklahoma state tax credits associated with the production from its wind farms as well as earning Oklahoma state tax credits associated with the Company’s investment in its electric generating facilities which further reduce the Company’s effective tax rate.

7.	Long-Term Debt

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

The Company has tax-exempt pollution control bonds with optional redemption provisions that allow the holders to request repayment of the bonds at various dates prior to the maturity. The bonds, which can be tendered at the option of the holder during the next 12 months, are as follows:

SERIES	DATE DUE	AMOUNT
		(In millions)
0.39% - 0.44%	Garfield Industrial Authority, January 1, 2025	$	47.0
0.38% - 0.44%	Muskogee Industrial Authority, January 1, 2025		32.4
0.50% - 0.50%	Muskogee Industrial Authority, June 1, 2027		56.0
Total (redeemable during next 12 months)		$	135.4

All of these bonds are subject to an optional tender at the request of the holders, at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. The bond holders, on any business day, can request repayment of the bond by delivering an irrevocable notice to the tender agent stating the principal amount of the bond, payment instructions for the purchase price and the business day the bond is to be purchased. The repayment option may only be exercised by the holder of a bond for the principal amount. When a tender notice has been received by the trustee, a third party remarketing agent for the bonds will attempt to remarket any bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of bonds in 1995 and 1997, the remarketing agent has

successfully remarketed all tendered bonds. If the remarketing agent is unable to remarket any such bonds, the Company is obligated to repurchase such unremarketed bonds. As the Company has both the intent and ability to refinance the bonds on a long-term basis and such ability is supported by an ability to consummate the refinancing, the bonds are classified as long-term debt in the Company’s Condensed Financial Statements. The Company believes that it has sufficient liquidity to meet these obligations.

8.	Short-Term Debt and Credit Facility

At March 31, 2011, there were $12.0 million in net outstanding advances from OGE Energy and at December 31, 2010, there were $68.9 million in net outstanding advances to OGE Energy. The Company has an intercompany borrowing agreement with OGE Energy whereby the Company has access to up to $250 million of OGE Energy’s revolving credit amount. This agreement has a termination date of January 9, 2013. At March 31, 2011, there were no intercompany borrowings under this agreement. The Company also has $389.0 million of liquidity under a bank facility which is available to back up the Company’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At March 31, 2011, there was $0.3 million supporting letters of credit at a weighted-average interest rate of 0.32 percent. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at March 31, 2011. At March 31, 2011, the Company had less than $0.1 million in cash and cash equivalents.

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

OGE Energy’s and the Company’s ability to access the commercial paper market could be adversely impacted by a credit ratings downgrade or major market disruptions. Pricing grids associated with OGE Energy’s and the Company’s credit facilities could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade could include an increase in the costs of OGE Energy’s and the Company’s short-term borrowings, but a reduction in OGE Energy’s and the Company’s credit ratings would not result in any defaults or accelerations. Any future downgrade of the Company could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit.

The Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2011 and ending December 31, 2012.

9. Retirement Plans and Postretirement Benefit Plans

The details of net periodic benefit cost of the Company’s portion of OGE Energy’s Pension Plan, the Restoration of Retirement Income Plan and the postretirement benefit plans included in the Condensed Financial Statements are as follows:

Net Periodic Benefit Cost

		Pension Plan				Restoration of Retirement Income Plan
		Three Months Ended				Three Months Ended
		March 31,				March 31,
(In millions)		2011		2010		2011		2010
Service cost		$	2.7	$	2.6	$	---	$	---
Interest cost			6.6		6.1		---		---
Expected return on plan assets			(9.3)		(8.6)		---		---
Amortization of net loss			3.9		3.9		---		---
Amortization of unrecognized prior service cost			0.6		0.6		0.1		0.1
Net periodic benefit cost (A)		$	4.5	$	4.6	$	0.1	$	0.1
(A)	In addition to the $4.6 million and $4.7 million of net periodic benefit cost recognized during the three months ended March 31, 2011 and 2010, respectively, the Company recognized an increase in pension expense during the three months ended March 31, 2011 and 2010 of $2.6 million and $1.9 million, respectively, to maintain the allowable amount to be recovered for pension expense in the Oklahoma jurisdiction which are identified as Deferred Pension Plan Expenses (see Note 1).

	Postretirement Benefit Plans
	Three Months Ended
	March 31,
(In millions)	2011		2010
Service cost	$	0.6	$	0.8
Interest cost		2.5		3.4
Expected return on plan assets		(1.2)		(1.7)
Amortization of transition obligation		0.6		0.6
Amortization of net loss		3.9		2.3
Amortization of unrecognized prior service cost		(3.4)		---
Net periodic benefit cost	$	3.0	$	5.4

Pension Plan Funding

OGE Energy previously disclosed in its 2010 Form 10-K that it may contribute up to $50 million to its Pension Plan during 2011, of which $47 million is expected to be the Company’s portion. In April 2011, OGE Energy contributed $20 million to its Pension Plan, of which $18.8 million was the Company’s portion. OGE Energy currently expects to contribute an additional $30 million during the remainder of 2011. Any remaining expected contributions to its Pension Plan during 2011 would be discretionary contributions, anticipated to be in the form of cash, and are not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended.

Postretirement Benefit Plan (Retiree Medical)

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

10. Commitments and Contingencies

Except as set forth below and in Note 11, the circumstances set forth in Notes 12 and 13 to the Company’s Financial Statements included in the Company’s 2010 Form 10-K appropriately represent, in all material respects, the current status of the Company’s material commitments and contingent liabilities.

Railcar Lease Agreement

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

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

The Company 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.

Wholesale Agreement

On May 28, 2009, the Company sent a termination notice to the Arkansas Valley Electric Cooperative that the Company would terminate its wholesale power agreement to all points of delivery where the Company sells or has sold power to the Arkansas Valley Electric Cooperative, effective November 30, 2011. In December 2010, the Company and the Arkansas Valley Electric Cooperative entered into a new wholesale power agreement whereby the Company will supply wholesale power to the Arkansas Valley Electric Cooperative through June 2015. On January 3, 2011, the Company submitted this agreement to the FERC for approval. The FERC approved the new wholesale power agreement on March 2, 2011 and the new contract was effective May 1, 2011. The Arkansas Valley Electric Cooperative contract contributed $17.4 million, or 1.5 percent, to the Company’s gross margin for the year ended December 31, 2010. The new Arkansas Valley Electric Cooperative contract is expected to add approximately $4 million in additional gross margin from May through December 2011 over the prior contract.

Other

In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by GAAP, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s Condensed Financial Statements. Except as otherwise stated above, in Note 11 below, in Item 1 of Part II of this Form 10-Q, in Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I of the Company’s 2010 Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

11. Rate Matters and Regulation

Except as set forth below, the circumstances set forth in Note 13 to the Company’s Financial Statements included in the Company’s 2010 Form 10-K appropriately represent, in all material respects, the current status of any regulatory matters.

Completed Regulatory Matter

SPP Cost Tracker

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

Pending Regulatory Matters

2010 Arkansas Rate Case Filing

On September 28, 2010, the Company filed a rate case with the APSC requesting a rate increase of $17.7 million, to recover the cost of significant electric system expansions and upgrades, including high-voltage transmission lines and wind energy, that have been completed since the last rate filing in August 2008, as well as rising operating costs. The Company

also sought recovery, through a rider, of the Arkansas jurisdictional portion of (i) costs associated with transmission upgrades and facilities that have been approved by the SPP in its regional planning processes and constructed by other non-Company transmission owners throughout the SPP that have been allocated to the Company through the FERC-approved transmission rates and (ii) SPP administrative fees. On March 15, 2011, the APSC Staff filed its recommendation, which included a $4.8 million rate increase and approval of the SPP rider for third-party transmission charges and SPP administrative fees. The Company filed its rebuttal testimony on April 5, 2011. On April 26, 2011, the APSC Staff filed surrebuttal testimony, which included support for an $8.8 million rate increase and recommended approval of an SPP rider for recovery of third-party transmission charges and SPP administrative fees of $0.8 million. The Arkansas office of the Attorney General and other parties to the proceeding have not agreed to the $9.6 million rate increase recommended by the APSC Staff. A hearing in this matter is scheduled for May 24, 2011.

Review of the Company’s Fuel Adjustment Clause for Calendar Year 2009

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

Smart Grid Project

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

FERC Transmission Rate Incentive Filing

On February 18, 2011, the Company submitted to the FERC a request seeking limited transmission rate incentives for five transmission projects. This February 18, 2011 request is in addition to the October 12, 2010 request described in the Company’s 2010 Form 10-K. The Company requested recovery of 100 percent of all prudently incurred construction work in progress in rate base for five 345 kV EHV transmission projects to be constructed and owned by the Company within the SPP’s region. The Company also requested to recover 100 percent of all prudently incurred development and construction costs if the transmission projects are abandoned or cancelled, in whole or in part, for reasons beyond the Company’s control. On April 19, 2011, the FERC granted these incentives for the Sooner-Rose Hill, Sunnyside-Hugo and Balanced Portfolio 3E transmission projects discussed in Note 13 of the Company’s 2010 Form 10-K.

Pension Tracker Modification Filing

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

Demand and Energy Efficiency Program Filing

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

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

Introduction

Overview

Financial Strategy

OGE Energy’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. OGE Energy intends to execute its vision by focusing on its regulated electric utility business and unregulated natural gas midstream business. OGE Energy intends to maintain the majority of its assets in the regulated utility business, however, OGE Energy anticipates significant growth opportunities for its natural gas midstream business.

Summary of Operating Results

Three Months Ended March 31, 2011 as Compared to Three Months Ended March 31, 2010

The Company reported net income of $6.4 million and $1.2 million, respectively, during the three months ended March 31, 2011 and 2010, an increase of $5.2 million, primarily due to a higher gross margin from the implementation of rate riders and lower income tax expense related to the elimination of the tax deduction for the Medicare Part D subsidy (as previously reported in the Company’s 2010 Form 10-K) partially offset by higher operation and maintenance expense.

Recent Developments and Regulatory Matters

SPP Cost Tracker

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

2011 Outlook

OGE Energy projects the Company to earn between $209 million and $219 million in 2011 which is unchanged from that previously reported in the Company’s 2010 Form 10-K. Please see the Company’s 2010 Form 10-K for the key factors and assumptions underlying its 2011 earnings guidance.

Results of Operations

The following discussion and analysis presents factors that affected the Company’s results of operations for the three months ended March 31, 2011 as compared to the same period in 2010 and the Company’s financial position at March 31, 2011. Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011 or for any future period. The following information should be read in conjunction with the Condensed Financial Statements and Notes thereto. Known trends and contingencies of a material nature are discussed to the extent considered relevant.

	Three Months Ended
	March 31,
(In millions)	2011		2010
Operating income	$	26.0	$	31.9
Net income	$	6.4	$	1.2

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

		Three Months Ended
		March 31,
(Dollars in millions)		2011		2010
Operating revenues		$	422.1	$	444.0
Cost of goods sold			219.4		250.8
Gross margin on revenues			202.7		193.2
Other operation and maintenance			105.8		93.9
Depreciation and amortization			51.8		49.7
Taxes other than income			19.1		17.7
Operating income			26.0		31.9
Interest income			0.1		---
Allowance for equity funds used during construction			4.4		2.3
Other income			5.0		2.5
Other expense			0.6		0.6
Interest expense			26.1		24.2
Income tax expense			2.4		10.7
Net income		$	6.4	$	1.2
Operating revenues by classification
Residential		$	176.8	$	191.2
Commercial			98.2		101.0
Industrial			44.1		45.5
Oilfield			34.9		35.6
Public authorities and street light			38.3		39.5
Sales for resale			13.2		16.7
System sales revenues			405.5		429.5
Off-system sales revenues			9.4		6.4
Other			7.2		8.1
Total operating revenues		$	422.1	$	444.0
MWH (A) sales by classification (in millions)
Residential			2.2		2.4
Commercial			1.5		1.4
Industrial			0.9		0.9
Oilfield			0.8		0.7
Public authorities and street light			0.7		0.7
Sales for resale			0.3		0.3
System sales			6.4		6.4
Off-system sales			0.3		0.1
Total sales			6.7		6.5
Number of customers			784,582		778,574
Average cost of energy per KWH (B) - cents
Natural gas			4.390		5.593
Coal			2.033		1.793
Total fuel			2.686		3.281
Total fuel and purchased power			3.048		3.551
Degree days (C)
Heating - Actual			1,820		2,140
Heating - Normal			1,963		1,963
Cooling - Actual			41		8
Cooling - Normal			8		8
(A)	Megawatt-hour
(B)	Kilowatt-hour
(C)	Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.

Three Months Ended March 31, 2011 as Compared to Three Months Ended March 31, 2010

Operating Income

The Company’s operating income decreased $5.9 million, or 18.5 percent, during the three months ended March 31, 2011 as compared to the same period in 2010 primarily due to higher other operation and maintenance expense partially offset by a higher gross margin as discussed below.

Gross Margin

Gross margin was $202.7 million during the three months ended March 31, 2011 as compared to $193.2 million during the same period in 2010, an increase of $9.5 million, or 4.9 percent. The gross margin increased primarily due to:

increased price variance, which included revenues from various rate riders, including the Windspeed rider, the Oklahoma demand program rider, the Smart Grid rider, the system hardening rider and the OU Spirit rider, and higher revenues from sales and customer mix, which increased the gross margin by $11.3 million;

higher demand and related revenues by non-residential customers in the Company’s service territory, which increased the gross margin by $2.5 million; and

new customer growth in the Company’s service territory, which increased the gross margin by $1.5 million.

These increases in the gross margin were partially offset by:

milder weather in the Company’s service territory, which decreased the gross margin by $3.4 million; and

lower other revenues due to lower SO2 allowance sales and fewer transmission requests from others on the Company’s system, which decreased the gross margin by $2.4 million.

Cost of goods sold for the Company consists of fuel used in electric generation, purchased power and transmission related charges. Fuel expense was $171.1 million during the three months ended March 31, 2011 as compared to $198.6 million during the same period in 2010, a decrease of $27.5 million, or 13.8 percent, primarily due to lower natural gas prices and lower natural gas generation. The Company’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 the Company and its customers. Purchased power costs were $46.4 million during the three months ended March 31, 2011 as compared to $51.7 million during the same period in 2010, a decrease of $5.3 million, or 10.3 percent, primarily due to a decrease in purchases in the energy imbalance service market and a decrease in cogeneration costs due to maintenance at one of the cogeneration plants in the first quarter of 2011 partially offset by an increase in short-term power purchases.

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 the Company’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 the Company pays to Enogex.

Operating Expenses

Other operation and maintenance expenses were $105.8 million during the three months ended March 31, 2011 as compared to $93.9 million during the same period in 2010, an increase of $11.9 million, or 12.7 percent. The increase in other operation and maintenance expenses was primarily due to:

an increase of $5.1 million in payroll and benefits expense and information technology support allocated from the holding company;

an increase of $3.3 million in other marketing and sales expense related to demand-side management initiatives, which expenses are being recovered through a rider;

an increase of $3.0 million in activity costs related to less work being capitalized in the first quarter of 2011; and

an increase of $1.2 million in contract technical and construction services expense and an increase of $0.5 million in materials and supplies expense primarily attributable to increased spending for ongoing maintenance at some of the Company’s power plants in the first quarter of 2011 as compared to the same period in 2010.

These increases in other operation and maintenance expenses were partially offset by:

a decrease of $1.5 million in overtime expense primarily due to the January 2010 ice storm; and

a decrease of $1.4 million in injuries and damages expense primarily due to lower reserves on claims in the first quarter of 2011.

Additional Information

Allowance for Equity Funds Used During Construction. AEFUDC was $4.4 million during the three months ended March 31, 2011 as compared to $2.3 million during the same period in 2010, an increase of $2.1 million, or 91.3 percent, primarily due to construction costs for Crossroads partially offset by the completion of the Windspeed transmission line on March 31, 2010.

Other Income. Other income was $5.0 million during the three months ended March 31, 2011 as compared to $2.5 million during the same period in 2010, an increase of $2.5 million, or 100.0 percent. The increase in other income was primarily due to:

an increase of $1.3 million related to the benefit associated with the tax gross-up of AEFUDC; and

an increase of $1.1 million due to an increased level of gains recognized in the GFB program during the first quarter of 2011 from more customers participating in the GFB program during the first quarter of 2011 and lower than expected usage resulting from milder weather.

Income Tax Expense. Income tax expense was $2.4 million during the three months ended March 31, 2011 as compared to $10.7 million during the same period in 2010, a decrease of $8.3 million, or 77.6 percent. The decrease in income tax expense was primarily due to:

lower pre-tax income during the three months ended March 31, 2011 as compared to the same period in 2010; and

the one-time, non-cash charge during the three months ended March 31, 2010 for the elimination of the tax deduction for the Medicare Part D subsidy.

Financial Condition

The balance of Advances to Parent was $68.9 million at March 31, 2011 with no balance at December 31, 2010, primarily due to payments for various transmission projects and Crossroads, bond interest and other operational needs.

The balance of Construction Work in Progress was $410.8 million and $328.1 million at March 31, 2011 and December 31, 2010, respectively, an increase of $82.7 million, or 25.2 percent, primarily due to increased spending on various transmission projects and Crossroads.

The balance of Regulatory Assets was $412.1 million and $489.4 million at March 31, 2011 and December 31, 2010, respectively, a decrease of $77.3 million, or 15.8 percent, primarily due to amendments to OGE Energy’s retiree medical plan adopted in January 2011 (see Note 9 of Notes to Condensed Financial Statements for a further discussion).

The balance of Accrued Interest was $25.1 million and $41.6 million at March 31, 2011 and December 31, 2010, respectively, a decrease of $16.5 million, or 39.7 percent, primarily due to the timing of interest payments on long-term debt in the first quarter of 2011 partially offset by interest accrued on long-term debt in the first quarter of 2011.

The balance of Accrued Benefit Obligations was $185.7 million and $259.8 million at March 31, 2011 and December 31, 2010, respectively, a decrease of $74.1 million, or 28.5 percent, primarily due to amendments to OGE Energy’s retiree medical plan adopted in January 2011 (see Note 9 of Notes to Condensed Financial Statements for a further discussion) partially offset by accruals for pension and postretirement benefits expense.

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 2010 Form 10-K.

Railcar Lease Agreement

Liquidity and Capital Resources

Cash Flows

	Three Months Ended
	March 31,
(In millions)	2011		2010
Net cash provided from operating activities	$	34.4	$	78.4
Net cash used in investing activities		(115.3)		(99.4)
Net cash provided from financing activities		80.9		21.0

The decrease of $44.0 million, or 56.1 percent, in net cash provided from operating activities during the three months ended March 31, 2011 as compared to the same period in 2010 was 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 repair expenditures partially offset by lower fuel refunds during the three months ended March 31, 2011 as compared to the same period in 2010 and cash received in the first quarter of 2011 from the implementation of rate riders.

The increase of $15.9 million, or 16.0 percent, in net cash used in investing activities during the three months ended March 31, 2011 as compared to the same period in 2010 primarily related to higher levels of capital expenditures during the three months ended March 31, 2011 related to various transmission projects and Crossroads partially offset by capital expenditures in 2010 related to Windspeed.

The increase of $59.9 million in net cash provided from financing activities during the three months ended March 31, 2011 as compared to the same period in 2010 was primarily due to the Company funding capital projects.

Future Capital Requirements and Financing Activities

The Company’s primary needs for capital are related to acquiring or constructing new facilities and replacing or expanding existing facilities in its electric utility business. Other working capital requirements are expected to be primarily related to maturing debt, operating lease obligations, hedging activities, 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, commercial paper and borrowings from OGE Energy) and permanent financings.

Capital Expenditures

The Company’s estimates of capital expenditures for the years 2011 through 2016 are shown in the following table. These capital expenditures represent the base maintenance capital expenditures (i.e., capital expenditures to maintain and operate the Company’s business) plus capital expenditures for known and committed projects.

(In millions)		2011		2012		2013		2014		2015		2016
Base Transmission		$	50	$	30	$	20	$	20	$	20	$	20
Base Distribution			225		200		200		200		200		200
Base Generation			105		80		70		70		70		70
Other			45		30		30		30		30		30
Total Base Transmission, Distribution,
Generation and Other			425		340		320		320		320		320
Known and Committed Projects:
Transmission Projects:
Sunnyside-Hugo (345 kV)			115		20		---		---		---		---
Sooner-Rose Hill (345 kV)			30		5		---		---		---		---
Balanced Portfolio 3E Projects			55		195		160		40		---		---
SPP Priority Projects			5		60		170		80		---		---
Total Transmission Projects			205		280		330		120		---		---
Other Projects:
Smart Grid Program (A)			75		70		25		30		10		10
Crossroads			235		35		---		---		---		---
System Hardening			20		---		---		---		---		---
Total Other Projects			330		105		25		30		10		10
Total Known and Committed Projects			535		385		355		150		10		10
Total capital expenditures (B)		$	960	$	725	$	675	$	470	$	330	$	330
(A)	These capital expenditures are net of the Smart Grid $130 million grant approved by the U.S. Department of Energy.
(B)	The capital expenditures above exclude any environmental expenditures associated with BART requirements due to the uncertainty regarding BART costs. As discussed in “– Environmental Laws and Regulations” below, pursuant to the Oklahoma SIP and the proposed Federal implementation plan, the Company would be expected to install low NOX burners and related equipment at the three affected generating stations. Preliminary estimates indicate the cost will be $100 million (plus or minus 30 percent). The proposed Federal implementation plan rejects portions of the Oklahoma SIP with respect to SO2 emissions and, if adopted as proposed, could result in a significant increase in capital expenditures to reduce SO2 emissions. For further information, see “– Environmental Laws and Regulations” below.

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

Pension Plan Funding

Security Ratings

Access to reasonably priced capital is dependent in part on credit and security ratings. Pricing grids associated with OGE Energy’s and the Company’s credit facilities could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrade could include an increase in the cost of OGE Energy’s and the Company’s short-term borrowings, but a reduction in OGE Energy’s and the Company’s credit ratings would not result in any defaults or accelerations. Any future downgrade of the Company could also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit.

Future Sources of Financing

Management expects that cash generated from operations and proceeds from the issuance of long and short-term debt and funds received from OGE Energy (from proceeds from the sales of its common stock to the public through OGE Energy’s DRIP/DSPP 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, commercial paper and borrowings from OGE Energy) 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 Facility

The Company 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, 2011 and ending December 31, 2012. See Note 8 of Notes to Condensed Financial Statements for a discussion of the Company’s short-term debt activity.

Critical Accounting Policies and Estimates

The Condensed Financial Statements and Notes to Condensed Financial Statements contain information that is pertinent to Management’s Discussion and Analysis. In preparing the Condensed 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 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 Financial Statements. However, the Company believes it has taken reasonable, but conservative, positions where assumptions and estimates are used in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, contingency reserves, asset retirement obligations, fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the Company’s critical accounting estimates have been discussed with OGE Energy’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 2010 Form 10-K.

Commitments and Contingencies

Except as disclosed otherwise in this Form 10-Q and the Company’s 2010 Form 10-K, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows. See Notes 10 and 11 of Notes to Condensed Financial Statements in this Form 10-Q and Notes 12 and 13 of Notes to Financial Statements and Item 3 of Part I of the Company’s 2010 Form 10-K for a discussion of the Company’s commitments and contingencies.

Environmental Laws and Regulations

The activities of the Company 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 the Company’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to mitigate harm to threatened or endangered species and requiring the installation and operation of pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the

issuance of orders enjoining future operations. 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 2010 Form 10-K. Except as set forth below and in Part II, Item 1. Legal Proceedings, there have been no material changes to such items.

Air

Hazardous Air Pollutants Emission Standards

On March 16, 2011, the EPA issued proposed Maximum Achievable Control Technology regulations governing emissions of certain hazardous air pollutants from utility boilers. The proposal includes numerical standards for particulate matter, hydrogen chloride and mercury emissions from coal-fired boilers. In addition, the proposal includes work practice standards and an annual emission test to control dioxins and furans. Under the proposed rules, compliance is required within three years after finalization of the rule with a possibility of a one year extension. The EPA will accept comments on the proposal for 60 days after it is published. Currently, the EPA is under a consent decree deadline to issue a final rule by November 2011. The Company is evaluating what emission controls would be necessary to meet the proposed standards and the associated costs, which could be significant.

Regional Haze Control Measures

As described in the Company’s 2010 Form 10-K, on February 18, 2010, Oklahoma submitted its SIP to the EPA, which set forth the state’s plan for compliance with the Federal regional haze rule. The SIP concluded that BART for reducing NOX emissions at all of the subject units should be the installation of low NOX burners (overfire air and flue gas recirculation was also required on two of the units) and set forth associated NOX emission rates and limits. The Company preliminarily estimates that the total cost of installing and operating these NOX controls on all covered units, based on recent industry experience and past projects, will be between $70 million and $130 million. With respect to SO2 emissions, the SIP included an agreement between the ODEQ and the Company that established BART for SO2 control at four coal-fired units located at the Company’s Sooner and Muskogee generating stations as the continued use of low sulfur coal (along with associated emission rates and limits). The SIP specifically rejected the installation and operation of Dry Scrubbers as BART for SO2 control from these units because the state determined that Dry Scrubbers were not cost effective on these units.

On March 22, 2011, the EPA proposed to reject portions of the Oklahoma SIP and proposed a Federal implementation plan. While the EPA accepted Oklahoma’s BART determination for NOX in the SIP, it rejected the SO2 BART determination for the Company. In its place, the EPA has proposed that the Company meet an SO2 emission rate of 0.06 lbs/MMBtu. The Company could meet the proposed standard by either installation and operation of Dry Scrubbers or fuel switching at the four coal-fired generating units at the Company’s Muskogee and Sooner generating stations. The Company estimates that installing Dry Scrubbers on these units would cost the Company more than $1.0 billion. The EPA’s proposal will be subject to the normal administrative process that includes public notice and comment and the availability of judicial review. The Company plans to participate actively in this process to advocate for a final determination that does not require the installation of Dry Scrubbers.

Until the EPA takes final action on the Oklahoma SIP, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty. The Company 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 the Company’s retail customers under House Bill 1910, which was enacted into law in May 2005.

Notice of Violation

As previously reported, in July 2008, the Company received a request for information from the EPA regarding Federal Clean Air Act compliance at the Company’s Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Federal Clean Air Act’s new source review process. The Company believes it has acted in full compliance with the Federal Clean Air Act and new source review process and is cooperating with the EPA. On April 26, 2011, the EPA issued a notice of violation alleging that 13 projects that occurred at the Company’s Muskogee and Sooner generating plants between 1993 and 2006 without the required new source review permits. The notice of violation also alleges that the Company’s visible emissions at its Muskogee and Sooner generating plants are not in accordance with applicable new source performance standards (See Part II, Item 1 – Legal Proceedings – Opacity Notice for a related discussion). The Company is evaluating its response to the notice and cannot predict at this time what, if any, further actions may be necessary as a result of the notice. The EPA could seek to require the Company to install additional pollution control equipment and pay fines and penalties as a result of the allegations in the notice of violation.

Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation.

Water Intakes

In March 2011, the EPA proposed rules pursuant to Section 316(b) of the Federal Clean Water Act to address impingement and entrainment of aquatic organisms at existing cooling water intake structures. When final rules are issued and implemented, additional capital and/or increased operating costs may be incurred. The costs of complying with the final water intake standards are not currently determinable, but could be significant.

For additional information regarding contingencies relating to environmental laws and regulations, see Note 10 of Notes to Condensed Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Under the reduced disclosure format permitted by General Instruction H(2)(c) of Form 10-Q, the information otherwise required by Item 3 has been omitted.

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 SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer and chief financial officer , allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, of the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934), the chief executive officer and chief financial officer have concluded that the Company’s disclosure controls and procedures are effective.

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Reference is made to Part I, Item 3 of the Company’s 2010 Form 10-K for a description of certain legal proceedings presently pending. Except as set forth below, there are no new significant cases to report against the Company and there have been no material changes in the previously reported proceedings.

1. Opacity Notice. On March 18, 2011, the Company received notice from the GCELC of its intent to file a lawsuit against the Company. The notice was filed pursuant to the citizen suit provision of the Federal Clean Air Act and related to alleged violations of Federal and state opacity standards from March 18, 2006 to present at the Company’s Muskogee and Sooner generation stations. GCELC is seeking both injunctive relief to enjoin excess emissions from the Company’s Muskogee and Sooner generation stations and the assessment of civil penalties for alleged past violations of the applicable opacity limits. The Company and the ODEQ have been engaging in discussions about these alleged opacity violations for several years, and while the Company has denied that these events constitute violations of Federal and state standards, both parties continue to work toward resolution of the issue. If the ODEQ files a lawsuit on the alleged opacity violations before May 17, 2011, the GCELC will be prohibited from filing its lawsuit, although it may intervene in any such ODEQ lawsuit. At the present time, the Company does not believe that the resolution of this matter will have a material effect on its financial position, but Section 113 of the Federal Clean Air Act (along with the Federal Civil Penalties Inflation Adjustment Act of 1996) provides for civil penalties as much as $37,500 per day for each violation.

Item 1A. Risk Factors.

There have been no significant changes in the Company’s risk factors from those discussed in the Company’s 2010 Form 10-K, which are incorporated herein by reference.

Item 6. Exhibits.

Exhibit No.		Description
31.01		Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Schema Document.
101.PRE		XBRL Taxonomy Presentation Linkbase Document.
101.LAB		XBRL Taxonomy Label Linkbase Document.
101.CAL		XBRL Taxonomy Calculation Linkbase Document.
101.DEF		XBRL Definition Linkbase Document.

SIGNATURE

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

	OKLAHOMA GAS AND ELECTRIC COMPANY
	(Registrant)


By	/s/ Scott Forbes
	Scott Forbes
	Controller and Chief Accounting Officer

May 5, 2011

Attached files

OKLAHOMA GAS & ELECTRIC CO Reports

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