UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

(Mark one)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-12209

 

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200
Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code
(817) 870-2601

     Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable

     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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files).

Yes þ       No o

     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		Smaller Reporting Company o
				(Do not check if smaller reporting company)

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

Yes o       No þ

     159,421,086 Common Shares were outstanding on April 23, 2010.

 

 

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended March 31, 2010

     Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.

TABLE OF CONTENTS

		Page
PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements:
Consolidated Balance Sheets (Unaudited)			3
Consolidated Statements of Operations (Unaudited)			4
Consolidated Statements of Cash Flows (Unaudited)			5
Consolidated Statements of Comprehensive Income (Unaudited)			6
Selected Notes to Consolidated Financial Statements (Unaudited)			7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk			29
ITEM 4. Controls and Procedures			30
PART II — OTHER INFORMATION
ITEM 1A. Risk Factors			32
ITEM 6. Exhibits			32
EX-10.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

RANGE RESOURCES CORPORATION

		March 31, 2010				December 31, 2009
		(Unaudited)
Assets
Current assets:
Cash and equivalents		$	286,514			$	767
Accounts receivable, less allowance for doubtful accounts of $2,085 and $2,176			113,467				123,622
Deferred tax asset			—				8,054
Unrealized derivative gain			121,211				21,545
Assets held for sale			18,011				—
Inventory and other			21,743				21,292
Total current assets			560,946				175,280
Unrealized derivative gain			29,131				4,107
Equity method investments			147,662				146,809
Oil and gas properties, successful efforts method			6,122,859				6,308,707
Accumulated depletion and depreciation			(1,380,540	)			(1,409,888	)
			4,742,319				4,898,819
Transportation and field assets			133,330				161,034
Accumulated depreciation and amortization			(52,283	)			(69,199	)
			81,047				91,835
Other assets			80,996				79,031
Total assets		$	5,642,101			$	5,395,881
Liabilities
Current liabilities:
Accounts payable		$	214,854			$	214,548
Asset retirement obligations			2,446				2,446
Accrued liabilities			56,018				58,585
Deferred tax liability			17,309				—
Accrued interest			37,263				24,037
Unrealized derivative loss			10,016				14,488
Total current liabilities			337,906				314,104
Bank debt			354,000				324,000
Subordinated notes			1,384,194				1,383,833
Deferred tax liability			832,491				776,965
Unrealized derivative loss			—				271
Deferred compensation liability			127,749				135,541
Asset retirement obligations and other liabilities			70,825				82,578
Commitments and contingencies
Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $0.01 par, 475,000,000 shares authorized, 159,381,481 issued at March 31, 2010 and 158,336,264 issued at December 31, 2009			1,594				1,583
Common stock held in treasury, 215,425 shares at March 31, 2010 and 217,327 shares at December 31, 2009			(7,894	)			(7,964	)
Additional paid-in capital			1,805,251				1,772,020
Retained earnings			677,735				606,529
Accumulated other comprehensive income			58,250				6,421
Total stockholders’ equity			2,534,936				2,378,589
Total liabilities and stockholders’ equity		$	5,642,101			$	5,395,881

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended March 31,
		2010				2009
Revenues
Oil and gas sales		$	236,760			$	203,189
Transportation and gathering			2,093				(505	)
Derivative fair value income			42,333				75,547
Gain on the sale of assets			68,868				36
Other			(1,575	)			(1,830	)
Total revenues			348,479				276,437
Costs and expenses
Direct operating			31,040				35,541
Production and ad valorem taxes			8,070				8,257
Exploration			14,635				13,339
Abandonment and impairment of unproved properties			12,407				19,572
General and administrative			28,170				24,910
Termination costs			7,938				—
Deferred compensation plan			(5,712	)			12,434
Interest expense			30,287				26,629
Depletion, depreciation and amortization			88,626				84,320
Impairment of proved properties			6,505				—
Total costs and expenses			221,966				225,002
Income from operations			126,513				51,435
Income tax expense
Current			—				—
Deferred			48,934				18,827
Total income tax expense			48,934				18,827
Net income		$	77,579			$	32,608
Income per common share:
Basic		$	0.50			$	0.21
Diluted		$	0.48			$	0.21
Dividends per common share		$	0.04			$	0.04
Weighted average common shares outstanding:
Basic			156,393				153,719
Diluted			160,292				157,231

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended March 31,
		2010				2009
Operating activities:
Net income		$	77,579			$	32,608
Adjustments to reconcile net cash provided from operating activities:
Loss from equity method investments			1,621				919
Deferred income tax expense			48,934				18,827
Depletion, depreciation, amortization and proved property impairment			95,131				84,320
Exploration dry hole costs			—				123
Mark-to-market gain on oil and gas derivatives not designated as hedges			(46,578	)			(31,525	)
Abandonment and impairment of unproved properties			12,407				19,572
Unrealized derivative loss			249				453
Deferred and stock-based compensation			7,277				21,164
Amortization of deferred financing costs and other			1,167				1,050
Gain on sale of assets and other			(68,868	)			(4	)
Changes in working capital:
Accounts receivable			6,845				45,396
Inventory and other			(700	)			(1,722	)
Accounts payable			17,452				(38,099	)
Accrued liabilities and other			358				(3,921	)
Net cash provided from operating activities			152,874				149,161
Investing activities:
Additions to oil and gas properties			(166,244	)			(159,223	)
Additions to field service assets			(6,355	)			(6,106	)
Acreage purchases			(19,849	)			(84,405	)
Investment in equity method investment			—				248
Other assets			(45	)			—
Proceeds from disposal of assets			301,648				285
Purchase of marketable securities held by the deferred compensation plan			(3,690	)			(2,148	)
Proceeds from the sales of marketable securities held by the deferred compensation plan			2,613				1,250
Net cash provided from (used in) investing activities			108,078				(250,099	)
Financing activities:
Borrowing on credit facilities			148,000				250,000
Repayment on credit facilities			(118,000	)			(136,000	)
Dividends paid			(6,373	)			(6,257	)
Issuance of common stock			5,437				5,226
Change in cash overdrafts			(5,162	)			(12,726	)
Proceeds from the sales of common stock held by the deferred compensation plan			893				713
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases			—				(15	)
Net cash provided from financing activities			24,795				100,941
Increase in cash and equivalents			285,747				3
Cash and equivalents at beginning of period			767				753
Cash and equivalents at end of period		$	286,514			$	756

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended March 31,
		2010				2009
Net income		$	77,579			$	32,608
Other comprehensive (loss) income:
Realized gain on hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of taxes			(753	)			(32,333	)
Change in unrealized deferred hedging gains, net of taxes			52,582				46,181
Total comprehensive income		$	129,408			$	46,456

See accompanying notes.

RANGE RESOURCES CORPORATION

(1) ORGANIZATION AND NATURE OF BUSINESS

     We are engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern and the Appalachian regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range Resources Corporation is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2) BASIS OF PRESENTATION

     These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources 2009 Annual Report on Form 10-K filed on February 24, 2010. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (“SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements.

     Our oil and gas producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of production of reserves is calculated based on future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. When the carrying value exceeds the sum of future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to market participants) and the carrying value of the asset. Due to declining gas prices, we recognized proved property impairment expense for a Gulf Coast property of $6.5 million in first quarter 2010. The impairment charge reduced oil and gas properties’ carrying value to estimated fair value, represented by estimated discounted future cash flows, which were derived from Level 3 fair value inputs.

(3) NEW ACCOUNTING STANDARDS

     Variable interest accounting standards were amended by the FASB in June 2009. The new accounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated, and therefore will now be evaluated for consolidation in accordance with the applicable consolidation guidance. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended variable interest accounting standard requires reconsideration for determining whether an entity is a variable interest entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. Adoption did not have an impact on our consolidated results of operations, financial position or cash flows.

     A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the rollforward of Level 3 activity, and (4) the transfers in and out of Levels 1 and 2. We adopted the new disclosures in first quarter 2010.

(4) DISPOSITIONS

2010 Asset Sales

     In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio for $330.0 million. We closed approximately 90% of the sale on March 30, 2010 and expect to close the remainder of the sale in the next quarter. Our remaining Ohio assets are included as Assets held for sale on our March 31, 2010 consolidated balance sheet. Proceeds received in the first quarter were approximately $300.0 million and we recorded a gain of $67.0 million. The agreement has an effective date of January 1, 2010, and consequently operating net revenues after January 1, 2010 are downward adjustments to the selling price. The proceeds we received on March 30 were placed in a like-kind exchange account and are reflected in Cash and equivalents on our March 31, 2010 consolidated balance sheet. We may use some or all of these proceeds to purchase proved or unproved oil and gas properties. This asset sale is subject to typical post-closing adjustments. We expect the total proceeds from this transaction to approximate $323.0 million.

2009 Asset Sales

     In fourth quarter 2009, we sold natural gas properties in New York for proceeds of $36.3 million. The proceeds were credited to oil and gas properties, with no gain or loss recognized, as the sale did not materially impact the depletion rate of the remaining properties in the amortization base.

     In second quarter 2009, we sold oil properties located in West Texas for proceeds of $182.0 million. The proceeds were credited to oil and gas properties, with no gain or loss recognized, as the sale did not materially impact the depletion rate of the remaining properties in the amortization base.

(5) INCOME TAXES

     Income tax expense was as follows (in thousands):

		Three Months Ended
		March 31,
		2010				2009
Income tax expense		$	48,934			$	18,827
Effective tax rate			38.7	%			36.6	%

     We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended March 31, 2010 and 2009, our overall effective tax rate on pre-tax income from operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences.

(6) EARNINGS PER COMMON SHARE

     Basic income per share is based on weighted average number of common shares outstanding. Diluted income per share includes restricted stock, the exercise of stock options and stock appreciation rights (or SARs), provided the effect is not anti-dilutive. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

		Three Months Ended
		March 31,
		2010				2009
Numerator:
Net income		$	77,579			$	32,608
Denominator:
Weighted average common shares outstanding — basic			156,393				153,719
Effect of dilutive securities:
Employee stock options, SARs and stock held in the deferred compensation plan			3,899				3,512
Weighted average common shares — diluted			160,292				157,231
Income per common share:
Basic — net income		$	0.50			$	0.21
Diluted — net income		$	0.48			$	0.21

     The weighted average common shares — basic amount excludes 2.7 million shares of restricted stock at March 31, 2010 and 2.3 million shares of restricted stock at March 31, 2009 held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Stock appreciation rights for 1.1 million shares for the three months ended March 31, 2010 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations. Stock appreciation rights for 1.7 million shares for the three months ended March 31, 2009 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

(7) SUSPENDED EXPLORATORY WELL COSTS

     The following table reflects the changes in capitalized exploratory well costs for the three months ended March 31, 2010 and the year ended December 31, 2009 (in thousands):

		March 31,				December 31,
		2010				2009
Beginning balance at January 1		$	19,052			$	47,623
Additions to capitalized exploratory well costs pending the determination of proved reserves			4,351				26,216
Reclassifications to wells, facilities and equipment based on determination of proved reserves			(3,593	)			(52,849	)
Capitalized exploratory well costs charged to expense			—				(1,938	)
Balance at end of period			19,810				19,052
Less exploratory well costs that have been capitalized for a period of one year or less			(12,144	)			(10,778	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$	7,666			$	8,274
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			5				6

     The $19.8 million of capitalized exploratory well costs at March 31, 2010 was incurred in 2010 ($3.7 million), in 2009 ($8.4 million) and in 2008 ($7.7 million). Of the five projects that have exploratory costs capitalized for more than one year, all are Marcellus Shale wells and are waiting on the completion of pipelines.

(8) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at March 31, 2010 is shown parenthetically). No interest expense was capitalized during the three months ended March 31, 2010 and 2009.

		March 31,				December 31,
		2010				2009
Bank debt (2.2%)		$	354,000			$	324,000
Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount			198,466				198,362
6.375% Senior Subordinated Notes due 2015			150,000				150,000
7.5% Senior Subordinated Notes due 2016, net of discount			249,648				249,637
7.5% Senior Subordinated Notes due 2017			250,000				250,000
7.25% Senior Subordinated Notes due 2018			250,000				250,000
8.0% Senior Subordinated Notes due 2019, net of discount			286,080				285,834
Total debt		$	1,738,194			$	1,707,833

Bank Debt

     In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On March 31, 2010, the borrowing base was $1.5 billion and our facility amount was $1.25 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. As part of our semi-annual bank review completed March 31, 2010, our borrowing base was reaffirmed at $1.5 billion and our facility amount was also reaffirmed at $1.25 billion. Our current bank group is comprised of twenty-six commercial banks each holding between 2.4% and 5.0% of the total facility. The facility amount may be increased up to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility amount increase. At March 31, 2010, the outstanding balance under the bank credit facility was $354.0 million and $100,000 of undrawn letters of credit leaving $895.9 million of borrowing capacity available under the facility amount. The loan matures October 25, 2012. Borrowing under the bank credit facility can either be the Alternate Base Rate (as defined) plus a spread ranging from 0.875% to 1.625% or LIBOR borrowings at the adjusted LIBOR Rate (as defined) plus a spread ranging from 1.75% to 2.5%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any part of the base rate loans to LIBOR loans. The weighted average interest rate on the bank credit facility was 2.1% for the three months ended March 31, 2010 compared to 2.6% for the three months ended March 31, 2009. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.375% and 0.50%. At March 31, 2010, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.875% on our base rate loans. At April 23, 2010, the interest rate (including applicable margin) was 2.2%.

Senior Subordinated Notes

     In May 2009, we issued $300.0 million aggregate principal amount of 8.0% senior subordinated notes due 2019 (“8.0% Notes”). The 8.0% Notes were issued at a discount, which is being amortized over the life of the 8.0% Notes. Interest on the 8.0% Notes is payable semi-annually, in May and November, and is guaranteed by certain of our subsidiaries. We may redeem the 8.0% Notes, in whole or in part, at any time on or after May 15, 2014, at redemption prices of 104.0% of the principal amount as of May 15, 2014 declining to 100.0% on May 15, 2017 and thereafter. Before May 15, 2012, we may redeem up to 35% of the original aggregate principal amount of the 8.0% Notes at a redemption price equal to 108.0% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that at least 65% of the original aggregate principal amount of the 8.0% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering.

Debt Covenants

     Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in

the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at March 31, 2010.

     The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates or change the nature of our business. At March 31, 2010, we were in compliance with these covenants.

(9) ASSET RETIREMENT OBLIGATIONS

     Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. A reconciliation of our liability for plugging, abandonment and remediation costs for the three months ended March 31, 2010 is as follows (in thousands):

		Three Months Ended
		March 31,
		2010
Beginning of period		$	78,812
Liabilities incurred			380
Liabilities settled			(772	)
Liabilities sold			(12,638	)
Accretion expense			1,555
Change in estimate			—
End of period		$	67,337

     Accretion expense is recognized as a component of Depreciation, depletion and amortization expense on our consolidated statement of operations.

(10) CAPITAL STOCK

     We have authorized capital stock of 485 million shares, which includes 475 million shares of common stock and 10 million shares of preferred stock. The following is a summary of changes in the number of common shares outstanding since the beginning of 2009:

		Three Months				Year
		Ended				Ended
		March 31,				December 31,
		2010				2009
Beginning balance			158,118,937				155,375,487
Shares issued in lieu of cash bonuses			—				184,926
Stock options/SARs exercised			497,860				1,384,861
Restricted stock grants			167,128				413,353
Treasury shares			1,902				16,573
Issued for acreage purchases			380,229				743,737
Ending balance			159,166,056				158,118,937

Treasury Stock

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. During 2008, we repurchased 78,400 shares of common stock at an average price of $41.11 for a total of $3.2 million. We have $6.8 million remaining under this authorization.

(11) DERIVATIVE ACTIVITIES

     We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. Historically, our derivative activities have consisted of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. At March 31, 2010, we had collars covering 129.1 Bcf of gas at weighted average floor and cap prices of $5.69 to $7.22 per mcf and 0.3 million barrels of oil at weighted average floor and cap prices of $75.00 to $93.75 per barrel. The fair value of these collars, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and a reference price, generally New York Mercantile Exchange (“NYMEX”), on March 31, 2010, was a net unrealized pre-tax gain of $156.6 million. These contracts expire monthly through December 2011. We currently have not entered into any NGL derivative contracts.

     The following table sets forth our derivative volumes and average hedge prices as of March 31, 2010:

						Average
Period		Contract Type		Volume Hedged		Hedge Price
Natural Gas
2010		Collars		316,727 Mmbtu/day		$5.54-$7.21
2011		Collars		115,000 Mmbtu/day		$6.00-$7.24
Crude Oil
2010		Collars		1,000 bbl/day		$75.00-$93.75

     Every derivative instrument is recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying estimated market price at the determination date. Changes in the fair value of hedge derivatives are recorded as a component of accumulated other comprehensive income (“AOCI”) on our consolidated balance sheet, which is later transferred to oil and gas sales when the underlying physical transaction occurs and the hedging contract is settled. Amounts included in AOCI at March 31, 2010 and December 31, 2009 relate solely to our derivative activities. As of March 31, 2010, an unrealized pre-tax derivative gain of $93.8 million was recorded in AOCI. This gain is expected to be reclassified into earnings as a $59.2 million gain in 2010 and as a $34.6 million gain in 2011. The actual reclassification to earnings will be based on market prices at the contract settlement date.

     For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to oil and gas sales in the period the hedged production is sold. Oil and gas sales include $1.2 million of gains in the three months ended March 31, 2010 compared to gains of $51.3 million in the three months ended March 31, 2009 related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives is reflected as Derivative fair value income on our consolidated statement of operations. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. The three months ended March 31, 2010 include ineffective losses (unrealized and realized) of $606,000 compared to gains of $44,000 in the same period of 2009.

     Through March 2010, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas sales when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately as Derivative fair value income or loss on our consolidated statement of operations. During the first three months of 2010, there were no gains/losses recorded due to the discontinuance of hedge accounting treatment for these derivatives. During the first three months of 2009, there were gains of $2.3 million reclassified into earnings as a result of the discontinuance of hedge accounting treatment for some of our derivatives due to asset sales.

     Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge but provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and gas production. These contracts are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts as Derivative fair value income on our consolidated statement of operations (for additional information see table below).

     In addition to the collars discussed above, we have entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix a portion of our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $16.3 million at March 31, 2010 and these basis swaps expire through 2011.

Derivative Fair Value Income

     The following table presents information about the components of derivative fair value income in the three months ended March 31, 2010 and 2009 (in thousands):

		Three Months Ended
		March 31,
		2010				2009
Hedge ineffectiveness — realized		$	(357	)		$	497
— unrealized			(249	)			(453	)
Change in fair value of derivatives that do not qualify for hedge accounting(a)			46,578				31,525
Realized gain (loss) on settlements — gas(a) (b)			(3,639	)			38,372
Realized gain on settlements — oil (a) (b)			—				5,606
Derivative fair value income		$	42,333			$	75,547

     The combined fair value of derivatives included in our consolidated balance sheets as of March 31, 2010 and December 31, 2009 is summarized below (in thousands). We conduct commodity derivative activities with thirteen financial institutions, twelve of which are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. On our balance sheet, derivative assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty.

		March 31,				December 31,
		2010				2009
Derivative assets:
Natural gas — collars		$	153,151			$	26,649
— basis swaps			(2,691	)			(1,063	)
Crude oil — collars			(118	)			66
		$	150,342			$	25,652
Derivative liabilities:
Natural gas — collars		$	3,717			$	2,020
— basis swaps			(13,599	)			(16,779	)
Crude oil — collars			(134	)			—
		$	(10,016	)		$	(14,759	)

     The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our consolidated balance sheets (in thousands):

		March 31, 2010												December 31, 2009
		Assets				(Liabilities)								Assets				(Liabilities)
										Net												Net
		Carrying				Carrying				Carrying				Carrying				Carrying				Carrying
		Value				Value				Value				Value				Value				Value
Derivatives that qualify for cash flow hedge accounting:
Collars(1)		$	105,972			$	(253	)		$	105,719			$	22,062			$	—			$	22,062
		$	105,972			$	(253	)		$	105,719			$	22,062			$	—			$	22,062
Derivatives that do not qualify for hedge accounting:
Collars(1)		$	50,897			$	—			$	50,897			$	6,673			$	—			$	6,673
Basis swaps(1)			—				(16,290	)			(16,290	)			65				(17,907	)			(17,842	)
		$	50,897			$	(16,290	)		$	34,607			$	6,738			$	(17,907	)		$	(11,169	)

     The effects of our cash flow hedges on accumulated other comprehensive income (loss) on the consolidated balance sheets are summarized below:

		Three Months Ended March 31,
										Realized Gain (Loss)
		Change in Hedge								Reclassified from OCI into
		Derivative Fair Value								Revenue(a)
		2010				2009				2010				2009
Collars		$	84,811			$	74,080			$	1,215			$	51,323
Income taxes			(32,229	)			(27,899	)			(462	)			(18,990	)
		$	52,582			$	46,181			$	753			$	32,333

     The effects of our non-hedge derivatives and the ineffective portion of our hedge derivatives on our consolidated statements of operations is summarized below:

		Three Months Ended March 31,
		Gain (Loss) Recognized in								Gain (Loss) Recognized in								Derivative Fair Value
		Income (Non-hedge Derivatives)								Income (Ineffective Portion)								Income (Loss)
		2010				2009				2010				2009				2010				2009
Swaps		$	—			$	47,999			$	—			$	—			$	—			$	47,999
Collars			46,956				31,583				(606	)			44				46,350				31,627
Basis Swaps			(4,017	)			(4,079	)			—				—				(4,017	)			(4,079	)
Total		$	42,939			$	75,503			$	(606	)		$	44			$	42,333			$	75,547

(12)  FAIR VALUE MEASUREMENTS

     We use a market approach for our fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

		Fair Value Measurements at March 31, 2010 Using:
		Quoted Prices in				Significant								Total
		Active Markets				Other				Significant				Carrying
		for Identical				Observable				Unobservable				Value as of
		Assets				Inputs				Inputs				March 31,
		(Level 1)				(Level 2)				(Level 3)				2010
Trading securities held in the deferred compensation plans		$	46,581			$	—			$	—			$	46,581
Derivatives — collars			—				156,616				—				156,616
— basis swaps			—				(16,290	)			—				(16,290	)

     These items are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using March 31, 2010 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.

     Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included as Other assets on our consolidated balance sheet. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends and mark-to-market gains/losses are included as Deferred compensation plan expense on our consolidated statement of operations. For the three months ended March 31, 2010, interest and dividends were $32,000 and mark-to-market was a gain of $596,000. For the three months ended March 31, 2009, interest and dividends were $43,000 and the mark-to-market was a loss of $1.1 million. For additional information on the accounting for our deferred compensation plan, see Note 13.

     The following table presents the carrying amounts and the fair values of our financial instruments as of March 31, 2010 and December 31, 2009 (in thousands):

		March 31, 2010								December 31, 2009
		Carrying				Fair				Carrying				Fair
		Value				Value				Value				Value
Assets:
Commodity collars and basis swaps		$	150,342			$	150,342			$	25,652			$	25,652
Marketable securities(a)			46,581				46,581				43,554				43,554
Liabilities:
Commodity collars and basis swaps			(10,016	)			(10,016	)			(14,759	)			(14,759	)
Long-term debt(b)			(1,738,194	)			(1,839,894	)			(1,707,833	)			(1,826,458	)

Concentration of Credit Risk

     Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as necessary to limit risk of loss. Our allowance for uncollectible receivables was $2.1 million at March 31, 2010 and $2.2 million at December 31, 2009. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. As of March 31, 2010, these contracts consist of collars and basis swaps. This exposure

is diversified among major investment grade financial institutions and we have master netting agreements with the counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative counterparties include thirteen financial institutions, twelve of which are secured lenders in our bank credit facility. Our oil and gas assets provide collateral under our credit facility and our derivative exposure. J. Aron & Company is the only counterparty not in our bank group. At March 31, 2010, our net derivative payable includes a payable to J. Aron & Company of $2.1 million. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

     We have two active equity-based stock plans. Under these plans, incentive and nonqualified options, SARs and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors. All awards granted have been issued at prevailing market prices at the time of the grant. Since the middle of 2005, only SARs have been granted under the plans to limit the dilutive impact of our equity plans. Information with respect to stock option and SARs activities is summarized below:

						Weighted
						Average
						Exercise
		Shares				Price
Outstanding on December 31, 2009			7,154,712			$	31.38
Granted			862,091				46.46
Exercised			(627,064	)			16.82
Expired/forfeited			(28,869	)			45.63
Outstanding on March 31, 2010			7,360,870			$	34.33

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2010 was $16.70. The fair value of each stock option/SAR granted during 2010 was estimated as of the date of grant using the Black-Scholes-Merton option-pricing model based on the following average assumptions: risk-free interest rate of 1.6%; dividend yield of 0.3%; expected volatility of 48% and an expected life of 3.6 years. Of the 7.4 million stock option/SARs outstanding at March 31, 2010, 844,000 are stock options and 6.5 million are SARs.

Restricted Stock Grants

     During the first three months of 2010, 171,858 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $46.45 with a three-year vesting period. In the first three months of 2009, we issued 282,300 shares of restricted stock as compensation to employees at an average price of $34.24 with a three-year vesting period. We recorded compensation expense related to restricted stock grants which is based upon the market value of the shares on the date of grant of $5.1 million in the first three months of 2010 compared to $3.9 million in the three month period ended March 31, 2009. As of March 31, 2010, unrecognized compensation cost related to restricted stock awards was $21.2 million, which is expected to be recognized over the weighted average period of 1.8 years. All of our restricted stock grants are held in our deferred compensation plans. All restricted stock awards are classified as a liability award and remeasured at fair value each reporting period. This mark-to-market is reported as Deferred compensation plan expense in our consolidated statement of operations (see additional discussion below). All awards granted have been issued at prevailing market prices at the time of the grant and the vesting of these shares is based upon an employee’s continued employment with us.

     A summary of the status of our non-vested restricted stock outstanding at March 31, 2010 is presented below:

						Weighted
						Average Grant
		Shares				Date Fair Value
Non-vested shares outstanding at December 31, 2009			627,189			$	45.64
Granted			171,858				46.45
Vested			(124,532	)			45.35
Forfeited			(4,730	)			44.59
Non-vested shares outstanding at March 31, 2010			669,785			$	45.91

Deferred Compensation Plan

     Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest such amounts in Range common stock or make other investments at the individual’s discretion. The assets of the plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock granted and held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals either in cash or in Range stock. The liability associated with the vested portion of the stock is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than Range common stock, are invested in marketable securities and reported at market value as Other assets on our consolidated balance sheet. Changes in the market value of the securities are charged or credited to Deferred compensation plan expense each quarter. The Deferred compensation liability on our consolidated balance sheet reflects the vested market value of the marketable securities and Range common stock held in the Rabbi Trust. We recorded non-cash, mark-to-market income related to our deferred compensation plan of $5.7 million in first quarter 2010 compared to mark-to-market expense of $12.4 million in first quarter 2009.

(14) SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended
		March 31,
		2010				2009
		(in thousands)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net		$	376			$	1,121
Unproved property purchased with stock(a)		$	20,000			$	—
Market value of restricted stock issued		$	7,776			$	6,964
Shares of restricted stock issued			167				204
Net cash provided from operating activities included:
Interest paid		$	15,625			$	17,850
Income taxes refunded		$	(1,684	)		$	—

(15) COMMITMENTS AND CONTINGENCIES

Litigation

     We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

(16) CAPITALIZED COSTS AND ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION^(a)

		March 31,				December 31,
		2010				2009
		(in thousands)
Oil and gas properties:
Properties subject to depletion		$	5,363,575			$	5,534,204
Unproved properties			759,284				774,503
Total			6,122,859				6,308,707
Accumulated depreciation, depletion and amortization			(1,380,540	)			(1,409,888	)
Net capitalized costs		$	4,742,319			$	4,898,819

(17) COSTS INCURRED FOR PROPERTY ACQUISITIONS, EXPLORATION AND DEVELOPMENT^(a)

		Three Months				Year
		Ended				Ended
		March 31,				December 31,
		2010				2009
		(in thousands)
Acreage purchases(b)		$	19,842			$	176,867
Development			150,316				497,702
Exploration:
Drilling			12,341				57,121
Expense			13,499				42,082
Stock-based compensation expense			1,136				4,817
Gas gathering facilities			4,711				29,524
Subtotal			201,845				808,113
Asset retirement obligations			376				6,131
Total costs incurred		$	202,221			$	814,244

(18) OFFICE CLOSING AND EXIT ACTIVITIES

     In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio. We closed approximately 90% of the sale on March 30, 2010 and expect to close the remainder of the sale in second quarter 2010. The first quarter 2010 includes $5.1 million accrued severance costs which is reflected in Termination costs on our consolidated statement of operations. As part of their severance agreement, our Ohio employees’ vesting of SAR and restricted stock grants was accelerated, increasing our non-cash stock compensation expense in the first quarter 2010 by approximately $2.8 million.

     In third quarter 2009, we announced the closing of our Gulf Coast area office in Houston, Texas. In the year ended December 31, 2009, we accrued $1.3 million of severance costs. The properties are now operated out of our Southwest Area office in Fort Worth. Expenses related to lease termination and severance costs were included in General and administrative expenses in our consolidated statement of operations for 2009.

     In December 2009, we sold our natural gas properties in New York. In fourth quarter 2009, we accrued $635,000 of severance costs related to this divestiture and the costs were included in Direct operating expense in our consolidated statement of operations in 2009.

     The following table details our exit activities, which are included in accrued liabilities in our consolidated balance sheet as of March 31, 2010 (in thousands):

Balance at December 31, 2009		$	1,568
Accrued one-time termination costs			5,138
Payments			(837	)
Balance at March 31, 2010		$	5,869

(19) SUBSEQUENT EVENT

     On April 26, we entered into additional 2011 derivative contracts consisting of collars covering 51.1 Bcf of gas at weighted average floor and cap prices of $5.50 to $6.50 per mcf and 1.9 million barrels of oil at weighted average floor and cap prices of $70.00 to $90.00 per barrel.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2009 Annual Report on Form 10-K.

Critical Accounting Estimates and Policies

     The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. These policies and estimates are described in the 2009 Form 10-K. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: accounting for oil and gas revenue, oil and gas properties, stock-based compensation, derivative financial instruments, asset retirement obligations and deferred income taxes.

Results of Operations

Overview

     Total revenues increased $72.0 million, or 26% for first quarter 2010 over the same period of 2009. The increase includes a $33.6 million increase in oil and gas sales, a gain on the sale of our tight gas sand properties in Ohio of $67.0 million offset by a decrease in derivative fair value income of $33.2 million. Oil and gas sales vary due to changes in volumes of production sold and realized commodity prices. Due to volatility in oil and gas prices, realized prices decreased from the same period of the prior year, which was more than offset by an increase in production. For first quarter 2010, production increased 12% from the same period of the prior year while realized prices (including all derivative settlements) declined 16%. We believe oil and gas prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new regulations, new technology, and the level of oil and gas production in North America and worldwide. Although we have entered into derivative contracts covering a portion of our production volumes for 2010 and 2011, a sustained lower price environment would result in lower realized prices for unprotected volumes and reduce the prices we can enter into derivative contracts on additional volumes in the future.

     With the lower commodity price environment, we continue to focus our efforts on improving our operating efficiency. These efforts resulted in 22% lower direct operating expense per mcfe for first quarter 2010 when compared to the same period of the prior year. We will continue to pursue reductions in operating and well costs to align costs with a lower commodity price environment. We continue to experience increases in general and administrative expenses per mcfe as we continue to hire employees to staff our Marcellus Shale operations. However, on a per mcfe basis, our first quarter general and administrative expense was the same as the first quarter of the prior year. We also continue to see higher fixed interest expense per mcfe due to the issuances of new fixed rate senior subordinated notes at higher interest rates than our floating rate bank credit facility.

Oil and Gas Sales, Production and Realized Price Calculation

     Our oil and gas sales vary from quarter to quarter as a result of changes in realized commodity prices and volumes of production sold. Hedges included in oil and gas sales reflect settlement on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in our consolidated statement of operations category called derivative fair value income. The following table summarizes the primary components of oil and gas sales for the three months ended March 31, 2010 and 2009 (in thousands):

		Three Months Ended
		March 31,
		2010				2009				Change				%
Oil wellhead		$	35,884			$	28,080			$	7,804				28	%
Oil hedges realized			—				9,365				(9,365	)			(100	%)
Total oil sales		$	35,884				37,445				(1,561	)			(4	%)
Gas wellhead			163,770				116,920				46,850				40	%
Gas hedges realized			1,215				41,958				(40,743	)			(97	%)
Total gas sales			164,985				158,878				6,107				4	%
NGL			35,891				6,866				29,025				423	%
Combined wellhead			235,545				151,866				83,679				55	%
Combined hedges			1,215				51,323				(50,108	)			(98	%)
Total oil and gas sales		$	236,760			$	203,189			$	33,571				17	%

     Our production continues to grow through continued drilling success as we place new wells into production, partially offset by the natural decline of our oil and gas wells and asset sales. For first quarter 2010, our production volumes increased, from the same period of the prior year, 46% in our Appalachian Area and decreased 9% in our Southwestern Area. Natural gas liquid (“NGL”) production increased 96% due to increased rich gas production in our Appalachia Area along with an increase in processing capacity in the region. Crude oil production declined primarily due to the sale of oil properties in West Texas effective June 30, 2009. Our production for the three months ended March 31, 2010 and 2009 is shown below:

		Three Months Ended
		March 31,
		2010				2009				Change				%
Production:
Crude oil (bbls)			514,678				721,960				(207,282	)			(29	%)
NGLs (bbls)			831,136				423,261				407,875				96	%
Natural gas (mcf)			33,750,559				30,552,333				3,198,226				10	%
Total (mcfe)(a)			41,825,443				37,423,659				4,401,784				12	%
Average daily production:
Crude oil (bbls)			5,719				8,022				(2,303	)			(29	%)
NGLs (bbls)			9,235				4,703				4,532				96	%
Natural gas (mcf)			375,006				339,470				35,536				10	%
Total (mcfe)(a)			464,727				415,818				48,909				12	%

     Our average realized price (including all derivative settlements) received for oil and gas was $5.57 per mcfe in first quarter 2010 compared to $6.62 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlement for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months ended March 31, 2010 and 2009 are shown below:

		Three Months Ended
		March 31,
		2010				2009
Average sales prices (wellhead):
Crude oil (per bbl)		$	69.72			$	38.89
NGLs (per bbl)		$	43.18			$	16.22
Natural gas (per mcf)		$	4.85			$	3.82
Total (per mcfe)(a)		$	5.63			$	4.06
Average realized price (including derivatives that qualify for hedge accounting):
Crude oil (per bbl)		$	69.72			$	51.87
NGLs (per bbl)		$	43.18			$	16.22
Natural gas (per mcf)		$	4.89			$	5.20
Total (per mcfe)(a)		$	5.66			$	5.43
Average realized price (including all derivative settlements):
Crude oil (per bbl)		$	69.72			$	59.64
NGLs (per bbl)		$	43.18			$	16.22
Natural gas (per mcf)		$	4.77			$	6.47
Total (per mcfe)(a)		$	5.57			$	6.62
Average NYMEX prices(b)
Oil (per bbl)		$	78.81			$	43.20
Natural gas (per mcf)		$	5.37			$	4.86

     Derivative fair value income was $42.3 million in first quarter 2010 compared to $75.5 million in the same period of 2009. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income. We have also entered into basis swap agreements, which do not qualify for hedge accounting and are also marked to market. Not using hedge accounting treatment creates volatility in our revenues as unrealized gains and losses from non-hedge derivatives are included in total revenues and are not included in AOCI in our consolidated balance sheet. Hedge ineffectiveness, also included in this statement of operations category, is associated with our hedging contracts that qualify for hedge accounting.

     The following table presents information about the components of derivative fair value income for the three months March 31, 2010 and 2009 (in thousands):

		Three Months Ended
		March 31,
		2010				2009
Hedge ineffectiveness – realized(c)		$	(357	)		$	497
– unrealized(a)			(249	)			(453	)
Change in fair value of derivatives that do not qualify for hedge accounting(a)			46,578				31,525
Realized gain (loss) on settlements – gas(b)(c)			(3,639	)			38,372
Realized gain (loss) on settlements – oil(b)(c)			—				5,606
Derivative fair value income		$	42,333			$	75,547

     Gain on the sale of assets for first quarter 2010 increased $68.8 million from the same period of the prior year. In the first quarter, we closed on the sale of approximately 90% of our tight gas sand properties in Ohio and received proceeds of approximately $300.0 million for a gain of $67.0 million. We expect to close the remainder of the sale of our Ohio properties in the next quarter. We also expect proceeds for the entire transaction to be approximately $323.0 million.

     Other loss for first quarter 2010 decreased to a loss of $1.6 million compared to a loss of $1.8 million in the same period of 2009. First quarter 2010 includes a loss from equity method investments of $1.6 million. The first quarter of 2009 includes a loss from equity method investments of $918,000.

     We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about these expenses on an mcfe basis for the three months March 31, 2010 and 2009:

		Three Months Ended
		March 31,
		2010				2009				Change				%
Direct operating expense		$	0.74			$	0.95			$	(0.21	)			(22	%)
Production and ad valorem tax expense			0.19				0.22				(0.03	)			(14	%)
General and administrative expense			0.67				0.67				—				—	%
Interest expense			0.72				0.71				0.01				1	%
Depletion, depreciation and amortization expense			2.12				2.25				(0.13	)			(6	%)

     Direct operating expense declined $4.5 million in first quarter 2010 to $31.0 million. We experience increases in operating expenses as we add new wells and maintain production from existing properties. In first quarter 2010, this effect was more than offset by lower overall industry costs, lower workovers and asset sales. The first quarter 2009 included $3.9 million of operating costs related to properties sold in the second and fourth quarter 2009. On a per mcfe basis, excluding expenses on these same properties that have been sold, our 2009 direct operating expense would have been $0.89. On an absolute dollar basis, our spending for direct operating expense (excluding workovers) declined 12% for the three months ended March 31, 2010 despite higher production levels, due to cost containment measures and lower overall industry costs. We incurred $1.4 million ($0.03 per mcfe) of workover costs in first quarter 2010 versus $1.7 million ($0.05 per mcfe) in 2009. On a per mcfe basis, direct operating expenses for first quarter 2010 decreased $0.21, or 22%, from the same period of 2009 with the decrease consisting primarily of lower workover costs ($0.02 per mcfe), lower utility costs ($0.02 per mcfe), lower water disposal costs ($0.04 per mcfe), lower overall well service costs and asset sales. Stock-based compensation included in this category represents amortization of restricted stock grants and expense related to SAR grants. The following table summarizes direct operating expenses per mcfe for the three months ended March 31, 2010 and 2009:

		Three Months Ended
		March 31,
		2010				2009				Change				%
Lease operating expense		$	0.70			$	0.88			$	(0.18	)			(20	%)
Workovers			0.03				0.05				(0.02	)			(40	%)
Stock-based compensation (non-cash)			0.01				0.02				(0.01	)			(50	%)
Total direct operating expenses		$	0.74			$	0.95			$	(0.21	)			(22	%)

     Production and ad valorem taxes are paid based on market prices and not hedged prices. For the first quarter, these taxes decreased $187,000 or 2% from the same period of the prior year due to lower property taxes and an increase in production volume not subject to production taxes somewhat offset by higher market prices. On a per mcfe basis, production and ad valorem taxes decreased to $0.19 in first quarter 2010 from $0.22 in the same period of 2009.

     General and administrative expense for first quarter 2010 increased $3.3 million from the same period of the prior year due primarily to higher stock-based compensation ($1.6 million), slightly higher salaries and benefits ($735,000) and higher office expenses. Stock-based compensation included in this category represents amortization of restricted stock grants and expense related to SAR grants. The following table summarizes general and administrative expenses per mcfe for the three months ended March 31, 2010 and 2009:

		Three Months Ended
		March 31,
		2010				2009				Change				%
General and administrative		$	0.49			$	0.50			$	(0.01	)			(2	%)
Stock-based compensation (non-cash)			0.18				0.17				0.01				6	%
Total general and administrative expenses		$	0.67			$	0.67			$	—				—	%

     Termination costs in the first quarter include severance costs of $5.1 million related to the sale of our tight gas sand properties in Ohio and $2.8 million of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Ohio personnel.

     Interest expense for first quarter 2010 increased $3.7 million from the same period of the prior year due to the refinancing of certain debt from floating to higher fixed rates which was somewhat offset by lower overall debt balances. In May 2009, we issued $300.0 million of 8.0% senior subordinated notes due 2019, which added $6.0 million of interest costs in first quarter 2010. The proceeds from the issuance were used to retire lower floating interest rate bank debt, to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for first quarter 2010 was $359.6 million compared to $787.2 million for the same period of the prior year and the weighted average interest rates were 2.1% in first quarter 2010 compared to 2.6% in the same period of the prior year.

     Depletion, depreciation and amortization (“DD&A”) increased $4.3 million, or 5%, to $88.6 million in first quarter 2010. The increase was due to a 12% increase in production and was partially offset by a 6% decrease in depletion rates. On a per mcfe basis, DD&A decreased from $2.25 in first quarter 2009 to $2.12 in first quarter 2010. The following table summarizes DD&A expenses per mcfe for the three months ended March 31, 2010 and 2009:

		Three Months Ended
		March 31,
		2010				2009				Change				%
Depletion and amortization		$	1.97			$	2.09			$	(0.12	)			(6	%)
Depreciation			0.11				0.12				(0.01	)			(8	%)
Accretion and other			0.04				0.04				—				—	%
Total DD&A expense		$	2.12			$	2.25			$	(0.13	)			(6	%)

     Impairment of proved properties in first quarter 2010 of $6.5 million was recognized due to declining gas prices and is related to our Gulf Coast properties. Our estimated fair value of producing properties is generally calculated as the discounted present value of future net cash flows. Our estimates of cash flow are based on the latest available proved reserve and production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices.

     Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expenses. In the three months ended March 31, 2010 and 2009, stock-based compensation represents the amortization of restricted stock grants and expenses related to SAR grants. In first quarter 2010, stock-based compensation is a component of direct operating expense ($493,000), exploration expense ($1.1 million), general and administrative expense ($7.8 million) and termination costs ($2.8 million) for a total of $12.6 million. In first quarter 2009, stock-based compensation was a component of direct operating expense ($730,000), exploration expense ($1.1 million) and general and administrative expense ($6.2 million) for a total of $8.3 million.

     Exploration expense increased $1.3 million in first quarter 2010 primarily due to higher delay rental costs. The following table details our exploration-related expenses for the three months ended March 31, 2010 and 2009 (in thousands):

		Three Months Ended
		March 31,
		2010				2009				Change				%
Dry hole expense		$	—			$	123			$	(123	)			(100	%)
Seismic			7,681				8,198				(517	)			(6	%)
Personnel expense			2,730				2,856				(126	)			(4	%)
Stock-based compensation expense			1,136				1,074				62				6	%
Delay rentals and other			3,088				1,088				2,000				184	%
Total exploration expense		$	14,635			$	13,339			$	1,296				10	%

     Abandonment and impairment of unproved properties expense was $12.4 million during the three months ended March 31, 2010 compared to $19.6 million during the same period of 2009. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists evaluation of the property and the remaining months in the lease term for the property. Impairment of a individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success.

     Deferred compensation plan expense was income of $5.7 million in first quarter 2010 compared to expense of $12.4 million in the same period of the prior year. Our stock price decreased from $49.85 at December 31, 2009 to $46.87 at March 31, 2010. During the same period in the prior year, our stock price increased from $34.39 at December 31, 2008 to $41.16 at March 31, 2009. This non-cash expense relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in the deferred compensation plan. Our deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense.

     Income tax expense for first quarter 2010 increased to $48.9 million from $18.8 million in first quarter 2009, reflecting a 146% increase in income from operations before taxes compared to the same period of 2009. First quarter 2010 provided for tax expense at an effective rate of 38.7% compared to tax expense at an effective rate of 36.6% in the same period of 2009. We expect our effective tax rate to be approximately 38.5% for 2010.

Liquidity, Capital Resources and Capital Commitments

     Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with both uncommitted and committed availability, asset sales and access to both the debt and equity capital markets. We currently estimate our 2010 capital spending will approximate $950.0 million, excluding acquisitions. We continue to take steps to ensure adequate capital resources and liquidity to fund our capital expenditure program. During first quarter 2010, we sold our shallow tight sand Ohio properties for proceeds of approximately $300.0 million. We expect to close the second part of this sale in the second quarter for additional proceeds of approximately $20.0 million. We may use these proceeds to purchase or develop additional oil and gas proved or unproved properties. In first quarter 2010, we also entered into additional natural gas commodity derivative contracts for 2010 and 2011 to protect future cash flows. As part of our

semi-annual bank review completed March 31, 2010, our borrowing base and facility amounts were reaffirmed at $1.5 billion and $1.25 billion.

     During the three months ended March 31, 2010, our cash provided from operating activities was $152.9 million and we spent $172.6 million on capital expenditures and $19.8 million on acreage purchases. At March 31, 2010, we had $286.5 million in cash, total assets of $5.6 billion and a debt-to-capitalization ratio of 40.7%. Long-term debt at March 31, 2010 totaled $1.7 billion, which included $354.0 million of bank credit facility debt and $1.4 billion of senior subordinated notes. Available committed borrowing capacity under the bank credit facility at March 31, 2010 was $895.9 million.

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales will be adequate to satisfy near-term financial obligations and liquidity needs. However, our long-term cash flows are subject to a number of variables, including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. Sustained lower oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We currently have approximately 65% of our total 2010 production subject to hedging agreements. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices, which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

     Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies.

Credit Arrangements

     On March 31, 2010, the bank credit facility had a $1.5 billion borrowing base and a $1.25 billion facility amount. The borrowing base represents an amount approved by the bank group that can be borrowed based on our assets, while our $1.25 billion facility amount is the amount we have requested that the banks commit to fund pursuant to the credit agreement. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. Remaining credit availability was $845.9 million on April 23, 2010. Our bank group is comprised of twenty-six commercial banks, with no one bank holding more than 5.0% of the bank credit facility. We believe our large number of banks and relatively low hold levels allow for significant lending capacity should we elect to increase our $1.25 billion commitment up to the $1.5 billion borrowing base and also allow for flexibility should there be additional consolidation within the banking sector.

     Our bank credit facility and our indentures governing our senior subordinated notes all contain covenants that, among other things, limit our ability to pay dividends, incur additional indebtedness, sell assets, enter into hedging contracts change the nature of our business or operations, merge or consolidate or make certain investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with these covenants at March 31, 2010. Please see Note 8 to our consolidated financial statements for additional information.

Cash Flow

     Cash flows from operating activities primarily are affected by production and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operating activities also are impacted by changes in working capital. We sell substantially all of our oil and gas production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by higher prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowing under the credit facility. As of March 31, 2010, we have entered into hedging agreements covering 88.8 Bcfe for 2010 and 42.0 Bcfe for 2011.

     Net cash provided from operating activities for the three months ended March 31, 2010 was $152.9 million compared to $149.2 million in the three months ended March 31, 2009. Cash flow from operating activities for the first three months of 2010 was higher than the same period of the prior year, as higher production from development activity was somewhat offset by lower realized prices. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in the consolidated statement of cash flows) in the three months ended March 31, 2010 was $24.0 million compared to $1.7 million in the same period of the prior year.

     Net cash provided from investing activities for the three months ended March 31, 2010 was $108.1 million compared to net cash used in investing activities of $250.1 million in the same period of 2009. The first three months of 2010 included $166.2 million of additions to oil and gas properties and $19.8 million of acreage purchases offset by proceeds of $301.6 million from asset sales. Acquisitions for the first three months of 2010 include the purchase of Marcellus Shale leasehold acreage for $16.5 million. The first three months of 2009 included $159.2 million of additions to oil and gas properties and $84.4 million of acreage purchases and other investments.

     Net cash provided from financing for the three months ended March 31, 2010 was $24.8 million compared to $100.9 million in the first three months of 2009. In the first three months of 2010, we borrowed $148.0 million under our bank credit facility compared to borrowings of $250.0 million in the same period of the prior year. During the first three months of 2010, total debt increased $30.4 million.

Dividends

     On March 1, 2010, the Board of Directors declared a dividend of four cents per share ($6.4 million) on our common stock, which was paid on March 31, 2010 to stockholders of record at the close of business on March 15, 2010.

Capital Requirements and Contractual Cash Obligations

     We currently estimate our 2010 capital spending will approximate $950.0 million (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow and property sales. We may, from time to time during 2010, make borrowings under our credit facility but expect that for all of 2010 to require no significant incremental borrowing from our 2009 levels, assuming no change in our 2010 capital spending plans. Acreage purchases during the first quarter include $16.5 million of purchases in the Marcellus Shale and $1.8 million in the Barnett Shale, which were funded with borrowings under our credit facility. For the three months ended March 31, 2010, $177.3 million of our development and exploration spending was funded with internal cash flow and proceeds from asset sales. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may sell assets, issue subordinated notes or other debt securities, or issue additional shares of stock to fund capital expenditures or acquisitions, extend maturities or repay debt.

     Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportation commitments and other liabilities. Since December 31, 2009, there have been no material changes to our contractual obligations.

Other Contingencies

     We are involved in various legal actions and claims arising in the ordinary course of business. We believe the resolution of these proceedings will not have a material adverse effect on our liquidity or consolidated financial position.

Hedging – Oil and Gas Prices

     We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. These contracts consist of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital program. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. In light of current worldwide economic uncertainties, we recently have employed a strategy to hedge a portion of our production looking out 12 to 24 months from each quarter. At March 31, 2010, we had collars covering 129.1 Bcf of gas at weighted average floor and cap prices of $5.69 and $7.22 per mcf and 0.3 million barrels of oil at weighted average floor and cap prices of $75.00 and $93.75 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of contract prices and a reference price, generally NYMEX, on March 31, 2010 was a net unrealized pre-tax gain of $156.6 million. The contracts expire monthly through December 2011. Settled transaction gains and losses for derivatives that qualify for hedge accounting are determined monthly and are included as increases or

decreases in oil and gas sales in the period the hedged production is sold. In the first three months of 2010, oil and gas sales included realized hedging gains of $1.2 million compared to gains of $51.3 million in the first three months of 2009.

     At March 31, 2010, the following commodity derivative contracts were outstanding:

										Average
Period		Contract Type				Volume Hedged				Hedge Price
Natural Gas
2010		Collars				316,727 Mmbtu/day				$	5.54-$7.21
2011		Collars				115,000 Mmbtu/day				$	6.00-$7.24
Crude Oil
2010		Collars				1,000 bbl/day				$	75.00-$93.75

     Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge but provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and gas production. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value as Unrealized derivative gains and losses on our consolidated balance sheet. We recognize all unrealized and realized gains and losses related to these contracts as Derivative fair value income in our consolidated statement of operations. As of March 31, 2010, derivatives on 38.5 Bcfe no longer qualify or are not designated for hedge accounting.

     In addition to the swaps and collars above, we have entered into basis swap agreements that do not qualify for hedge accounting and are marked to market. The price we receive for our production can be less than NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $16.3 million at March 31, 2010.

Interest Rates

     At March 31, 2010, we had $1.7 billion of debt outstanding. Of this amount, $1.4 billion bore interest at fixed rates averaging 7.4%. Bank debt totaling $354.0 million bears interest at floating rates, which averaged 2.2% at March 31, 2010. The 30-day LIBOR rate on March 31, 2010 was 0.2%.

Debt Ratings

     We receive debt credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investor Services, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s rating for us is BB with a stable outlook. Moody’s rating for us is Ba2 with a stable outlook. We believe that S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels, asset, and proved reserve mix. A reduction in our debt ratings could negatively impact our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Inflation and Changes in Prices

     Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to fluctuations that are beyond our ability to control or predict. During first quarter 2010, we received an average of $69.72 per barrel of oil and $4.85 per mcf of gas before derivative contracts compared to $38.89 per barrel of oil and $3.82 per mcf of gas in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated through the middle of 2008, commodity prices for oil and gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends put pressure not only on our operating costs but also on capital costs. Due to the decline in commodity prices since then, costs have moderated. We expect costs in 2010 to continue to be a function of supply and demand.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposures. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

Financial Market Risk

     The debt and equity markets have exhibited adverse conditions since late 2007. The unprecedented volatility and upheaval in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. At this point, we do not believe our liquidity has been materially affected by the recent events in the global markets and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the capital markets. Additionally, we will continue to monitor events and circumstances surrounding each of our twenty-six lenders in the bank credit facility. Beginning in late 2009 and continuing into first quarter 2010, we have observed improving market conditions. Bank lending availability and access to long-term debt markets have improving market conditions. Bank lending availability and access to long-term debt markets have improved considerably from 2008.

Market Risk

     Our major market risk is exposure to oil and gas prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Oil and gas prices have been volatile and unpredictable for many years.

Commodity Price Risk

     We periodically enter into derivative arrangements with respect to our oil and gas production. These arrangements are intended to reduce the impact of oil and gas price fluctuations. At times, certain of our derivatives have been swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which establish a minimum floor price and a predetermined ceiling price. Historically, we applied hedge accounting to derivatives utilized to manage price risk associated with our oil and gas production. Accordingly, we recorded change in the fair value of our swap and collar contracts under the balance sheet caption accumulated other comprehensive income and into oil and gas sales when the forecasted sale of production occurred. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge is reported currently each period under our consolidated statement of operations caption derivative fair value income. Some of our derivatives do not qualify for hedge accounting but provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and gas production. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value on our consolidated balance sheet under the captions unrealized derivative gains and losses. We recognize all unrealized and realized gains and losses related to these contracts in our consolidated statement of operations under the caption derivative fair value income. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction. Our derivative counterparties include thirteen financial institutions, twelve of which are in our bank group. J. Aron & Company is the counterparty not in our bank group. At March 31, 2010, our net derivative payable includes a payable to J. Aron & Company of $2.2 million. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.

     As of March 31, 2010, we had collars covering 129.1 Bcf of gas and 0.3 million barrels of oil. These contracts expire monthly through December 2011. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of March 31, 2010, approximated a net unrealized pre-tax gain of $156.6 million.

     At March 31, 2010, the following commodity derivative contracts were outstanding:

														Fair Market Value
														as of
														March 31, 2010
Period		Contract Type				Volume Hedged				Average Hedge Price				Asset (Liability)
														(in thousands)
Natural Gas
2010		Collars				316,727 Mmbtu/day				$	5.54-$7.21			$	118,397
2011		Collars				115,000 Mmbtu/day				$	6.00-$7.24			$	38,472
Crude Oil
2010		Collars				1,000 bbl/day				$	75.00-$93.75			$	(253	)