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.

     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

157,733,941 Common Shares were outstanding on October 20, 2009.

 

 

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended September 30, 2009

     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 (Loss) (Unaudited)			6
		Selected Notes to Consolidated Financial Statements (Unaudited)			7
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			33
Item 4.		Controls and Procedures			34
PART II — OTHER INFORMATION
Item 6.		Exhibits			35
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
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares)

		September 30, 2009				December 31, 2008
		(Unaudited)
Assets
Current assets:
Cash and equivalents		$	859			$	753
Accounts receivable, less allowance for doubtful accounts of $1,888 and $954			97,172				162,201
Unrealized derivative gain			78,410				221,430
Inventory and other			20,735				19,927
Total current assets			197,176				404,311
Unrealized derivative gain			—				5,231
Equity method investments			151,824				147,126
Oil and gas properties, successful efforts method			6,300,946				6,028,980
Accumulated depletion and depreciation			(1,429,007	)			(1,186,934	)
			4,871,939				4,842,046
Transportation and field assets			164,102				142,662
Accumulated depreciation and amortization			(69,824	)			(56,434	)
			94,278				86,228
Other assets			81,165				66,937
Total assets		$	5,396,382			$	5,551,879
Liabilities
Current liabilities:
Accounts payable		$	135,881			$	250,640
Asset retirement obligations			2,118				2,055
Accrued liabilities			59,328				47,309
Deferred tax liability			2,462				32,984
Accrued interest			37,002				20,516
Unrealized derivative loss			9,573				10
Total current liabilities			246,364				353,514
Bank debt			398,000				693,000
Subordinated notes and other long term debt			1,383,480				1,097,668
Deferred tax liability			759,406				779,218
Unrealized derivative loss			5,301				—
Deferred compensation liability			132,517				93,247
Asset retirement obligations and other liabilities			85,985				83,890
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, 157,591,936 issued at September 30, 2009 and 155,609,387 issued at December 31, 2008			1,576				1,556
Common stock held in treasury, 233,900 shares at September 30, 2009 and December 31, 2008			(8,557	)			(8,557	)
Additional paid-in capital			1,743,276				1,695,268
Retained earnings			629,632				685,568
Accumulated other comprehensive income			19,402				77,507
Total stockholders’ equity			2,385,329				2,451,342
Total liabilities and stockholders’ equity		$	5,396,382			$	5,551,879

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands, except per share data)

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Revenues
Oil and gas sales		$	202,122			$	347,720			$	597,834			$	1,002,726
Transportation and gathering			2,444				1,537				4,091				3,890
Derivative fair value (loss) income			(482	)			272,869				65,209				(47,582	)
Other			(443	)			544				(6,624	)			20,777
Total revenues			203,641				622,670				660,510				979,811
Costs and expenses
Direct operating			31,111				36,532				101,480				106,710
Production and ad valorem taxes			7,600				15,210				23,421				45,106
Exploration			11,102				19,149				35,809				55,204
Abandonment and impairment of unproved properties			24,053				5,055				84,579				10,653
General and administrative			30,568				24,650				84,581				66,000
Deferred compensation plan			16,445				(37,515	)			29,635				(9,365	)
Interest expense			30,633				25,373				86,817				72,361
Depletion, depreciation and amortization			97,208				76,690				270,241				218,938
Total costs and expenses			248,720				165,144				716,563				565,607
(Loss) income from operations			(45,079	)			457,526				(56,053	)			414,204
Income tax (benefit) expense
Current			(695	)			2,374				(76	)			4,209
Deferred			(14,566	)			170,202				(18,884	)			152,551
Total income tax (benefit) expense			(15,261	)			172,576				(18,960	)			156,760
Net (loss) income		$	(29,818	)		$	284,950			$	(37,093	)		$	257,444
(Loss) income per common share:
Basic		$	(0.19	)		$	1.87			$	(0.24	)		$	1.71
Diluted		$	(0.19	)		$	1.81			$	(0.24	)		$	1.65
Dividends per common share		$	0.04			$	0.04			$	0.12			$	0.12
Weighted average common shares outstanding:
Basic			154,653				152,765				154,257				150,487
Diluted			154,653				157,729				154,257				155,896

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

		Nine Months Ended September 30,
		2009				2008
Operating activities:
Net (loss) income		$	(37,093	)		$	257,444
Adjustments to reconcile net cash provided from operating activities:
Loss (gain) from equity method investments			6,548				(170	)
Deferred income tax (benefit) expense			(18,884	)			152,551
Depletion, depreciation and amortization			270,241				218,938
Exploration dry hole costs			342				9,337
Mark-to-market on oil and gas derivatives not designated as hedges			83,393				3,184
Abandonment and impairment of unproved properties			84,579				10,653
Unrealized derivative loss (gain)			483				(1,862	)
Deferred and stock-based compensation			58,844				13,413
Amortization of deferred financing costs and other			3,742				2,137
Loss (gain) on sale of assets and other			2,660				(19,415	)
Changes in working capital:
Accounts receivable			38,373				(64,468	)
Inventory and other			(807	)			(5,263	)
Accounts payable			(67,076	)			2,927
Accrued liabilities and other			18,423				20,982
Net cash provided from operating activities			443,768				600,388
Investing activities:
Additions to oil and gas properties			(425,376	)			(646,403	)
Additions to field service assets			(21,959	)			(20,651	)
Acreage purchases			(118,724	)			(733,767	)
Investment in equity method investment			(6,099	)			(25,460	)
Other assets			8,604				(25,496	)
Proceeds from disposal of assets			182,230				66,693
Purchase of marketable securities held by the deferred compensation plan			(6,932	)			(9,300	)
Proceeds from the sales of marketable securities held by the deferred compensation plan			3,155				6,605
Net cash used in investing activities			(385,101	)			(1,387,779	)
Financing activities:
Borrowing on credit facilities			582,000				1,219,000
Repayment on credit facilities			(877,000	)			(972,500	)
Dividends paid			(18,843	)			(18,404	)
Debt issuance costs			(6,399	)			(5,710	)
Issuance of subordinated notes			285,201				250,000
Issuance of common stock			8,368				288,643
Change in cash overdrafts			(37,690	)			20,785
Proceeds from the sales of common stock held by the deferred compensation plan			6,049				5,135
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases			(247	)			(3,311	)
Net cash (used in) provided from financing activities			(58,561	)			783,638
Increase (decrease) in cash and equivalents			106				(3,753	)
Cash and equivalents at beginning of period			753				4,018
Cash and equivalents at end of period		$	859			$	265

See accompanying notes.

RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)

		Three Months Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
Net (loss) income		$	(29,818	)		$	284,950			$	(37,093	)		$	257,444
Other comprehensive (loss) income:
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive (loss) income			(34,248	)			25,538				(100,070	)			53,300
Change in unrealized deferred hedging gains (losses)			(1,218	)			222,569				41,965				(60,157	)
Total comprehensive (loss) income		$	(65,284	)		$	533,057			$	(95,198	)		$	250,587

See accompanying notes.

RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(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 our current report on Form 8-K filed on August 10, 2009 (see additional information below). 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. We have evaluated events or transactions that occurred subsequent to September 30, 2009 through the date and time this quarterly report on Form 10-Q was filed.

     In second quarter 2009, we identified certain mineral leases amounting to $8.2 million that expired in 2006, 2007, and 2008, which were not expensed as required. Based on Staff Accounting Bulletin No. 108 (“SAB 108”), we determined that these amounts were immaterial to each of the periods affected and, therefore, we were not required to amend our previously filed reports. However, if these adjustments were recorded in 2009, we believe the impact could be material to this year. Therefore, on August 10, 2009, we adjusted our previously reported results for 2006, 2007, and 2008 for these immaterial amounts (as required by SAB 108), by filing on Form 8-K revised consolidated financial statements for 2006, 2007 and 2008. In addition to recording additional mineral lease expirations, we made four other adjustments to prior year numbers to correct other immaterial items, which included the following adjustments: (1) tax expense of $3.5 million for discrete tax items recorded in 2008 related to 2007 (2) expense for volumetric ineffectiveness related to our derivative positions of $1.7 million recorded in 2008 related to 2007 (3) dry hole expense of $2.4 million not recorded in 2007 and (4) deferred compensation income of $7.1 million recorded in 2007 related to 2006 and prior years. The balance sheet as of December 31, 2008 has been adjusted to reflect the cumulative impact of such adjustments. As a result, oil and gas properties decreased by $10.7 million, deferred tax liability decreased $4.2 million and retained earnings decreased by $6.5 million. The effect of these adjustments on the three months and the nine months September 30, 2008 was to decrease net income $374,000 in the third quarter 2008 and increase net income $5.0 million for the nine months ended September 30, 2008.

     We follow Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic 932 “Extractive Activities-Oil and Gas” for recognizing impairment of capitalized costs related to unproved properties. These costs are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We also consider time, geologic and engineering factors to evaluate the need for impairment of these costs. We continue to experience an increase in lease expirations and impairment expense caused by (1) current economic conditions, which have impacted our future drilling plans thereby increasing the amount of expected lease expirations and (2) the expansion of our unproved property positions in new shale plays. As economic conditions change and we continue to evaluate unproved properties, our estimates of expirations will likely change and we may increase or decrease impairment expense. We recorded abandonment and impairment expense in the three and nine months ended September 30, 2009 of $24.1 million and $84.6 million compared to $5.1 million and $10.7 million in the same periods of the prior year. The nine months ended September 30, 2009 includes the expiration of certain sizeable Barnett Shale leases.

(3) NEW ACCOUNTING STANDARDS

     In February 2008, the FASB issued Accounting Standards Codification (“ASC”) 820 — 10 (formerly Financial Staff Position SFAS No. 157-2), which delayed the effective date of ASC 820 - 10 (formerly SFAS No. 157) for all non-financial assets and non-financial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This deferral primarily applied to our asset retirement obligation, which uses fair value measures at the date incurred to determine our liability and any property impairments that may occur. We adopted the provisions of this standard effective January 1, 2009 and the adoption did not have a material effect on our consolidated results of operations or financial position.

     In June 2008, the FASB issued ASC 260 — 10 (formerly Staff Position No. EITF 03-6-1), “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities,” which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. We adopted the provisions of this standard on January 1, 2009 with no impact on our reported earnings per share.

     In March 2008, the FASB issued ASC 815- 10 (formerly SFAS No. 161), which amends and expands disclosure requirements with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why any entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this standard were adopted on January 1, 2009. See Note 11 for additional disclosures about our derivative instruments and hedging activities.

     In December 2007, the FASB issued ASC 805-10 (formerly SFAS No. 141(R)), “Business Combinations,” which retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase method of accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The provisions of this standard will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009 and the adoption did not have an impact on our financial position or results of operations.

     In April 2009, the FASB issued additional application guidance and enhancements to disclosures regarding fair value measurements. ASC 825-10 (formerly FASB Staff Position No. FAS 107-1 and APB 28-1), “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. ASC 820 — 10 (formerly “FASB Staff Position No. FAS 157-4”), “Determining Fair Value when the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions that are Not Orderly,” provides guidelines for making fair value measurements more consistent. We adopted the provisions of these standards for the period ended June 30, 2009, which did not have an impact on our financial position or results of operations.

     In May 2009, the FASB issued ASC 855-10 (formerly SFAS No. 165), “Subsequent Events,” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard upon issuance with no impact on our financial position or results of operations.

     In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168), “Accounting Standards Codification^TM and the Hierarchy of Generally Accepted Accounting Principles.” The FASB Accounting Standards Codification^TM (“Codification”) has become the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in accordance with GAAP. All existing accounting standard documents are superseded by the Codification and any accounting literature not included in the Codification will not be authoritative. However, rules and interpretive releases of the SEC issued under the authority of federal securities laws will continue to be the source of authoritative generally accepted accounting principles for SEC registrants. Effective September 30, 2009, all references made to GAAP in our consolidated financial statements will include the new Codification numbering system along with original references. The Codification does not change or alter existing GAAP and, therefore, will not have an impact on our financial position, results of operations or cash flows.

(4) DISPOSITIONS

     In second quarter 2009, we sold certain oil properties located in West Texas for proceeds of $182.0 million. The proceeds from the sale of these properties were credited to oil and gas properties, with no gain or loss recognized, as the disposition did not materially impact the depletion rate of the remaining properties in the amortization base. In first quarter 2008, we sold East Texas properties for proceeds of $64.4 million and recorded a gain of $20.1 million.

(5) INCOME TAXES

Income tax expense (benefit) was as follows (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Income tax (benefit) expense		$	(15,261	)		$	172,576			$	(18,960	)		$	156,760
Effective tax rate			33.9	%			37.7	%			33.8	%			37.8	%

     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 (loss), 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 September 30, 2009, our overall effective tax rate on pre-tax loss from operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences. For the three months ended September 30, 2008, 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 and valuation allowance. For the nine months ended September 30, 2009, our overall effective tax rate on loss from operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowance and other permanent differences. For the nine months September 30, 2008, our overall effective tax rate on income from operations was different than the statutory rate due primarily to state income taxes.

(6) EARNINGS (LOSS) PER COMMON SHARE

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Numerator:
Net (loss) income		$	(29,818	)		$	284,950			$	(37,093	)		$	257,444
Denominator:
Weighted average common shares outstanding — basic			154,653				152,765				154,257				150,487
Effect of dilutive securities:
Employee stock options, SARs and stock held in the deferred compensation plan			—				4,964				—				5,409
Weighted average common shares — diluted			154,653				157,729				154,257				155,896
Loss per common share:
Basic — net (loss) income		$	(0.19	)		$	1.87			$	(0.24	)		$	1.71
Diluted — net (loss) income		$	(0.19	)		$	1.81			$	(0.24	)		$	1.65

     The weighted average common shares — basic amount excludes 2.7 million shares at September 30, 2009 and 2.3 million shares at September 30, 2008, of restricted stock that is held in our deferred compensation plan (although all restricted stock is issued and outstanding upon grant). Due to our net loss from operations for the three months and the nine months ended September 30, 2009, we excluded 7.6 million of outstanding stock options/SARs and 2.7 million of restricted stock held in our deferred compensation plans from the computations of diluted net loss per share because the effect would have been anti-dilutive. Stock appreciation rights for 1.1 million shares for the three months ended September 30, 2008 and 187,000 shares for the nine months ended September 30, 2008 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 nine months ended September 30, 2009 and the year ended December 31, 2008 (in thousands):

		September 30,				December 31,
		2009				2008
Beginning balance at January 1		$	47,623			$	15,053
Additions to capitalized exploratory well costs pending the determination of proved reserves			35,377				43,968
Reclassifications to wells, facilities and equipment based on determination of proved reserves			(12,234	)			(3,847	)
Capitalized exploratory well costs charged to expense			—				(7,551	)
Balance at end of period			70,766				47,623
Less exploratory well costs that have been capitalized for a period of one year or less			(44,470	)			(41,681	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$	26,296			$	5,942
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			13				3

     The $70.8 million of capitalized exploratory well costs at September 30, 2009 was incurred in 2009 ($21.3 million), in 2008 ($43.5 million) and in 2007 ($6.0 million). Of the thirteen projects that have exploratory costs capitalized for more than one year, twelve projects are Marcellus Shale wells, which are waiting on the completions of pipelines.

(8) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at September 30, 2009 is shown parenthetically). No interest expense was capitalized during the three months or the nine months ended September 30, 2009 and 2008.

		September 30,				December 31,
		2009				2008
Bank debt (2.2%)		$	398,000			$	693,000
Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount			198,262				197,968
6.375% Senior Subordinated Notes due 2015			150,000				150,000
7.5% Senior Subordinated Notes due 2016, net of discount			249,626				249,595
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			285,592				—
Other			—				105
Total debt		$	1,781,480			$	1,790,668

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 September 30, 2009, 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 September 30, 2009, 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. Of those twenty-six banks, thirteen are domestic banks and thirteen are foreign banks or wholly owned subsidiaries of foreign banks. 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 September 30, 2009, the outstanding balance under the bank credit facility was $398.0 million

and there was $852.0 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 LIBO 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 2.2% for the three months ended September 30, 2009 compared to 4.3% for the three months ended September 30, 2008. The weighted average interest rate on the bank credit facility was 2.5% for the nine months ended September 30, 2009 compared to 4.7% in the same period of the prior year. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.375% and 0.50%. At September 30, 2009, 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 October 20, 2009, the interest rate (including applicable margin) was 2.1%.

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 September 30, 2009.

     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 September 30, 2009, we were in compliance with these covenants.

(9) ASSET RETIREMENT OBLIGATIONS

     Our asset retirement obligation primarily represents 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 nine months ended September 30, 2009 is as follows (in thousands):

		Nine Months Ended
		September 30,
		2009
Beginning of period		$	83,457
Liabilities incurred			1,364
Liabilities settled			(533	)
Liabilities sold			(7,287	)
Accretion expense			4,431
Change in estimate			2,551
End of period		$	83,983

     Accretion expense is recognized as a component of depreciation, depletion and amortization 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 2008:

						Year
		Nine Months Ended				Ended
		September 30,				December 31,
		2009				2008
Beginning balance			155,375,487				149,511,997
Public offering			—				4,435,300
Stock options/SARs exercised			1,032,671				1,339,536
Restricted stock grants			475,306				167,054
Treasury shares			—				(78,400	)
Issued for acreage purchases			474,572				—
Ending balance			157,358,036				155,375,487

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. These contracts consist of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At September 30, 2009, we had open swap contracts covering 7.1 Bcf of gas at prices averaging $8.16 per mcf. We also had collars covering 78.9 Bcf of gas at weighted average floor and cap prices of $5.96 to $7.70 per mcf and 0.6 million barrels of oil at weighted average floor and cap prices of $63.43 to $76.01 per barrel. Their fair value, 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 September 30, 2009, was a net unrealized pre-tax gain of $80.5 million. These contracts expire monthly through December 2010.

     The following table sets forth our derivative volumes and average hedge prices as of September 30, 2009:

						Average
Period		Contract Type		Volume Hedged		Hedge Price
Natural Gas
2009		Swaps		76,739 Mmbtu/day		$8.16
2009		Collars		184,837 Mmbtu/day		$7.64-$8.53
2010		Collars		169,671 Mmbtu/day		$5.50-$7.47
Crude Oil
2009		Collars		6,000 bbl/day		$63.43-$76.01

     As required by the Derivatives and Hedging Topic of the Codification, 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 effective cash flow hedges are recorded as a component of “Accumulated other comprehensive income (loss),” (“AOCI”) on our consolidated balance sheet which is later transferred to earnings when the underlying physical transaction occurs. Amounts included in AOCI at September 30, 2009 and December 31, 2008 relate solely to our derivative activities. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of the derivative are recognized in earnings. As of September 30, 2009, an unrealized pre-tax derivative gain of $30.8 million was recorded in AOCI. This gain is expected to be reclassified into earnings as a $38.3 million gain in 2009 and as a $7.5 million loss in 2010. 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 $54.4 million of gains in the three months ended September 30, 2009 compared to losses of $41.2 million in the three months ended September 30, 2008 related to settled hedging transactions. For the nine months ended September 30, 2009, oil and gas sales include $158.8 million of gains compared to losses of $86.0 million in the same period of the prior period related to settled hedging transactions. Any ineffectiveness associated with these hedges is reflected in the statement of operations caption called “Derivative fair value income (loss).” 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 September 30, 2009 include ineffective unrealized losses of $386,000 compared to unrealized gains of $4.6 million in the same period of 2008. The nine months ended September 30, 2009 include ineffective unrealized losses of $483,000 compared to unrealized gains of $1.9 million in the same period of 2008.

     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 in the statement of operations as a “Derivative fair value income or loss.” During the first nine months of 2009, there were gains of $5.4 million reclassified into earnings as a result of the discontinuance of hedge accounting treatment for these derivatives. Due to the sale of certain West Texas oil properties in the second quarter 2009, we liquidated four oil commodity contracts and received proceeds of $119,000 in July 2009.

     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. We recognize all unrealized and realized gains and losses related to these contracts in the consolidated statement of operations caption called “Derivative fair value income (loss)” (see table below).

     In addition to the swaps and 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 $16.9 million at September 30, 2009 and these basis swaps expire through 2011.

Derivative Fair Value (Loss) Income

     The following table presents information about the components of derivative fair value (loss) income in the three months and the nine months ended September 30, 2009 and 2008 (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Hedge ineffectiveness — realized		$	1,581			$	(213	)		$	3,159			$	2
— unrealized			(386	)			4,553				(483	)			1,862
Change in fair value of derivatives that do not qualify for hedge accounting(a)			(53,323	)			294,317				(83,393	)			(3,184	)
Realized gain (loss) on settlements — gas(a) (b)			51,619				(18,520	)			138,361				(30,192	)
Realized gain (loss) on settlements — oil (a) (b)			27				(7,268	)			7,565				(16,070	)
Derivative fair value (loss) income		$	(482	)		$	272,869			$	65,209			$	(47,582	)

     The combined fair value of derivatives included in our consolidated balance sheets as of September 30, 2009 and December 31, 2008 is summarized below (in thousands). We conduct derivative activities with thirteen financial institutions, eleven 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.

		September 30,				December 31,
		2009				2008
Derivative assets:
Natural gas — swaps		$	24,698			$	57,280
— collars			59,680				121,781
— basis swaps			(5,406	)			12,434
Crude oil — collars			(562	)			35,166
		$	78,410			$	226,661
Derivative liabilities:
Natural gas — swaps		$	—			$	—
— collars			(3,306	)			—
— basis swaps			(11,511	)			(10	)
Crude oil — collars			(57	)			—
		$	(14,874	)		$	(10	)

     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):

		September 30, 2009												December 31, 2008
		Assets				(Liabilities)								Assets				(Liabilities)
										Net
		Carrying Value				Carrying Value				Carrying Value				Carrying Value				Carrying Value				Net Carrying Value
Derivatives that qualify for cash flow hedge accounting:
Collars(1)		$	44,848			$	(1,964	)		$	42,884			$	124,193			$	—			$	124,193
		$	44,848			$	(1,964	)		$	42,884			$	124,193			$	—			$	124,193
Derivatives that do not qualify for hedge accounting:
Swaps(1)		$	24,697			$	—			$	24,697			$	57,280			$	—			$	57,280
Collars(1)			13,190				(318	)			12,872				32,754				—				32,754
Basis swaps(1)			594				(17,511	)			(16,917	)			12,481				(57	)			12,424
		$	38,481			$	(17,829	)		$	20,652			$	102,515			$	(57	)		$	102,458

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

		Three Months Ended September 30,
										Realized Gain (Loss)
		Change in Hedge								Reclassified from OCI into
		Derivative Fair Value								Revenue(a)
		2009				2008				2009				2008
Swaps		$	—			$	26,398			$	—			$	(22,893	)
Collars			(1,934	)			332,584				54,362				(18,298	)
Income taxes			716				(136,413	)			(20,114	)			15,653
		$	(1,218	)		$	222,569			$	34,248			$	(25,538	)

		Nine Months Ended September 30,
										Realized Gain (Loss)
		Change in Hedge								Reclassified from OCI into
		Derivative Fair Value								Revenue(a)
		2009				2008				2009				2008
Swaps		$	—			$	(39,276	)		$	—			$	(19,765	)
Collars			67,386				(57,750	)			158,842				(66,203	)
Income taxes			(25,421	)			36,869				(58,772	)			32,668
		$	41,965			$	(60,157	)		$	100,070			$	(53,300	)

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

		Three Months Ended September 30,
										Gain (Loss) Recognized in
		Gain (Loss) Recognized in								Income (Ineffective								Derivative Fair Value
		Income (Non-Hedge)								Portion)								Income (Loss)
		2009				2008				2009				2008				2009				2008
Swaps		$	6,540			$	194,821			$	—			$	802			$	6,540			$	195,623
Collars			4,976				70,819				1,195				3,538				6,171				74,357
Basis Swaps			(13,193	)			2,889				—				—				(13,193	)			2,889
Total		$	(1,677	)		$	268,529			$	1,195			$	4,340			$	(482	)		$	272,869

		Nine Months Ended September 30,
		Gain (Loss) Recognized in								Gain (Loss) Recognized in								Derivative Fair Value
		Income (Non-Hedge)								Income (Ineffective Portion)								Income (Loss)
		2009				2008				2009				2008				2009				2008
Swaps		$	60,098			$	(43,080	)		$	—			$	(655	)		$	60,098			$	(43,735	)
Collars			29,846				(19,731	)			2,676				2,519				32,522				(17,212	)
Basis Swaps			(27,411	)			13,365				—				—				(27,411	)			13,365
Total		$	62,533			$	(49,446	)		$	2,676			$	1,864			$	65,209			$	(47,582	)

(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 September 30, 2009 Using:
		Quoted Prices in
		Active Markets for				Significant Other				Significant				Total Carrying
		Identical				Observable				Unobservable				Value as of
		Assets				Inputs				Inputs				September 30,
		(Level 1)				(Level 2)				(Level 3)				2009
Trading securities held in the deferred compensation plans		$	44,428			$	—			$	—			$	44,428
Derivatives — swaps			—				24,698				—				24,698
— collars			—				55,755				—				55,755
— basis swaps			—				(16,917	)			—				(16,917	)

     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 September 30, 2009 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 in the balance sheet category called “other assets.” 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 in the statement of operations category called “Deferred compensation plan expense.” For the three months ended September 30, 2009, interest and dividends were $45,000 and mark-to-market was a gain of $5.7 million. For the three months ended September 30, 2008, interest and dividends were $52,000 and the mark-to-market was a loss of $6.3 million. For the nine months ended September 30, 2009, interest and dividends were $138,000 and mark-to-market was a

gain of $9.1 million. For the nine months ended September 30, 2008, interest and dividends were $319,000 and the mark-to-market was a loss of $11.5 million.

     The following table presents the carrying amounts and the fair values of our financial instruments as of September 30, 2009 and December 31, 2008 (in thousands):

		September 30, 2009								December 31, 2008
						Fair								Fair
		Carrying Value				Value				Carrying Value				Value
Assets:
Commodity swaps and collars		$	78,410			$	78,410			$	226,661			$	226,661
Marketable securities(a)			44,428				44,428				33,473				33,473
Liabilities:
Commodity swaps and collars			(14,874	)			(14,874	)			(10	)			(10	)
Long-term debt(b)			(1,781,480	)			(1,789,230	)			(1,790,668	)			(1,621,793	)

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 $1.9 million at September 30, 2009 and $954,000 at December 31, 2008. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. These contracts consist of collars and fixed price 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, eleven of which are secured lenders in our bank credit facility. Mitsui & Co. and J. Aron & Company are the two counterparties not in our bank group. At September 30, 2009, our net derivative asset includes a payable to J. Aron & Company of $965,000 and a receivable from Mitsui & Co. for $4.9 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, 2008			7,248,666			$	26.15
Granted			1,705,429				36.85
Exercised			(1,287,291	)			13.44
Expired/forfeited			(61,548	)			40.08
Outstanding on September 30, 2009			7,605,256			$	30.58

     The following table shows information with respect to outstanding stock options and SARs at September 30, 2009:

		Outstanding												Exercisable
						Weighted-				Weighted-								Weighted-
						Average				Average								Average
						Remaining				Exercise								Exercise
Range of Exercise Prices		Shares				Contractual Life				Price				Shares				Price
$1.29—$9.99			933,036				2.18			$	3.39				933,036			$	3.39
10.00—19.99			1,390,634				0.65				16.79				1,390,634				16.79
20.00—29.99			1,150,961				1.48				24.30				1,140,261				24.28
30.00—39.99			2,424,333				3.34				34.14				767,380				34.42
40.00—49.99			619,437				4.59				41.73				55,485				41.69
50.00—59.99			713,440				3.39				58.49				214,387				58.57
60.00—69.99			26,677				3.63				65.40				8,529				65.33
70.00—75.00			346,738				3.64				75.00				122,563				75.00
Total			7,605,256				2.54			$	30.58				4,632,275			$	22.72

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2009 was $15.41. The fair value of each stock option/SAR granted during 2009 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 1.5%; dividend yield of 0.4%; expected volatility of 59%; and an expected life of 3.5 years.

     As of September 30, 2009, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $158.6 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $128.7 million and 1.7 years. As of September 30, 2009, the number of fully vested awards and awards expected to vest was 7.5 million. The weighted average exercise price and weighted average remaining contractual life of these awards was $30.35 and 2.5 years and the aggregate intrinsic value was $157.2 million. As of September 30, 2009, unrecognized compensation cost related to the awards was $32.1 million, which is expected to be recognized over a weighted average period of 1.2 years. Of the 7.6 million stock option/SARs outstanding at September 30, 2009, 1.6 million are stock options and 6.0 million are SARs.

Restricted Stock Grants

     During the first nine months of 2009, 539,000 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $37.83 with a three-year vesting period and 22,700 shares were granted to our directors at an average price of $41.60 with immediate vesting. In the first nine months of 2008, we issued 314,000 shares of restricted stock as compensation to employees at an average price of $65.40 with a three-year vesting period and 10,800 shares were granted to our directors at a price of $75.00 with immediate vesting. 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 $13.1 million in the first nine months of 2009 compared to $10.7 million in the nine-month period ended September 30, 2008. As of September 30, 2009, unrecognized compensation cost related to restricted stock awards was $25.9 million, which is expected to be recognized over the weighted average period of 1.2 years (not including the mark-to-market expense (income) that would also be recognized over that same time period — see Deferred Compensation Plan discussion below). All of our restricted stock grants are held in our deferred compensation plans (see also 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 September 30, 2009 is presented below:

						Weighted
						Average Grant
		Shares				Date Fair Value
Non-vested shares outstanding at December 31, 2008			473,547			$	48.50
Granted			561,267				37.98
Vested			(367,700	)			40.45
Forfeited			(7,767	)			38.32
Non-vested shares outstanding at September 30, 2009			659,347			$	44.16

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 from the Rabbi Trust either in cash or in Range stock. The liability associated with the vested portion of the stock held in the Rabbi Trust 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 under the caption 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 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 expense related to our deferred compensation plan of $16.4 million in the third quarter 2009 and $29.6 million in the first nine months of 2009 compared to mark-to-market income of $37.5 million in the third quarter 2008 and $9.4 million in the first nine months of 2008.

(14) SUPPLEMENTAL CASH FLOW INFORMATION

		Nine Months Ended
		September 30,
		2009				2008
		(in thousands)
Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net		$	(3,373	)		$	(7,389	)
Unproved property purchased with stock		$	20,548			$	—
Net cash provided from operating activities included:
Interest paid		$	66,556			$	59,590
Income taxes paid (refunded)		$	(493	)		$	4,554

(15) COMMITMENTS AND CONTINGENCIES

Transportation Contracts

     We have entered firm transportation contracts with various pipelines. Under these contracts, we are obligated to transport minimum daily gas volumes, as calculated on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As of September 30, 2009, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):

2009 remaining		$	8,891
2010			34,663
2011			34,180
2012			31,220
2013			30,349
2014			27,070
Thereafter			207,240
		$	373,613

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)

		September 30,				December 31,
		2009				2008
		(in thousands)
Oil and gas properties:
Properties subject to depletion		$	5,534,009			$	5,271,021
Unproved properties			766,937				757,959
Total			6,300,946				6,028,980
Accumulated depreciation, depletion and amortization			(1,429,007	)			(1,186,934	)
Net capitalized costs		$	4,871,939			$	4,842,046

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

		Nine Months				Year
		Ended				Ended
		September 30,				December 31,
		2009				2008
		(in thousands)
Acquisitions:
Unproved leasehold		$	—			$	99,446
Proved oil and gas properties			445				251,471
Asset retirement obligations			—				251
Acreage purchases(b)			123,421				494,341
Development			376,254				729,268
Exploration:
Drilling			41,063				133,116
Expense			32,878				63,560
Stock-based compensation expense			2,933				4,130
Gas gathering facilities			19,959				47,056
Subtotal			596,953				1,822,639
Asset retirement obligations			(3,373	)			4,647
Total costs incurred		$	593,580			$	1,827,286

(18) OFFICE CLOSING

     We have announced the closing of our Gulf Coast Area administrative and operations office in Houston, Texas. The properties will be operated out of our Southwest Area office in Fort Worth effective November 1, 2009. As of September 30, 2009, we have accrued $840,000 of severance costs. At the time of closure, employee severance costs, and lease termination costs are not expected to be material. Expenses related to lease termination and severance costs are included in general and administrative expenses in our consolidated statement of operations.

(19) ACCOUNTING STANDARDS NOT YET ADOPTED

     In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

•

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

•

Require companies to report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The SEC indicated they will continue to communicate with the FASB staff to align FASB’s accounting standards with these rules. The FASB currently requires a single-day, year-end price for accounting purposes.

•

Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures.

•

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

•

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

•

Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.

•

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.

     We will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

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

     The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2008 Annual Report on Form 10-K, as well as the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For additional risk factors affecting our business, see the information in Item 1A. Risk Factors, in our 2008 Annual Report on Form 10-K and subsequent filings. The three months and the nine months ended September 30, 2008 have been adjusted for certain immaterial amounts. See also Note 2 of this report.

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 2008 Form 10-K except as updated below. 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 taxes.

     We adhere to FASB Accounting Standards Codification Topic 932 “Extractive Activities — Oil and Gas,” for recognizing impairment of capitalized costs related to unproved properties. These costs are capitalized and periodically evaluated (at least quarterly) as to recoverability based on changes brought about by economic factors and potential shifts in business strategy employed by management. We also consider time, geologic and engineering factors to evaluate the need for impairment of these costs. We continue to experience an increase in lease expirations and impairment expense caused by (1) current economic conditions, which have impacted our future drilling plans thereby increasing the amount of expected lease expirations, and (2) the rapid expansion of our unproved property positions in new shale plays. As economic conditions change and we continue to evaluate unproved properties, our estimates of expirations likely will change and we may increase or decrease impairment expense. We recorded abandonment and impairment expense in the three and nine months ended September 30, 2009 of $24.1 million and $84.6 million compared to $5.1 million and $10.7 million in the same periods of the prior year.

Results of Continuing Operations

Overview

     Total revenues declined $419.0 million, or 67% for third quarter 2009 over the same period of 2008. The decrease includes a $273.4 million decrease in derivative fair value (loss) income and a $145.6 million decrease in oil and gas sales. 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 dropped sharply from the same period of the prior year, which was partially offset by an increase in production. For third quarter 2009, production increased 13% from the same period of the prior year while realized prices declined 30%. For the nine months ended September 30, 2009, production also increased 13% from the same period of the prior year while realized prices declined 31%. 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.

     Despite a 13% increase in production volumes, oil and gas sales declined 42% when compared to the same period in the prior year. The oil and gas commodity price decline, which began during the second half of 2008, has continued through the first nine months of 2009, especially with regard to natural gas prices. However, signs of possible economic improvement have recently resulted in higher oil prices and a slight increase in natural gas prices. With the lower commodity price environment, we have focused our efforts on improving our operating efficiency. These efforts resulted in 25% lower direct operating expense per mcfe for the third quarter and 16% lower for the nine months ended September 30, 2009 when compared to the same periods of the prior year. However, as we continue to expand our Marcellus Shale team to meet the needs of this developing asset, we have seen upward pressure on our general and administrative costs per mcfe. To mitigate this trend, we have announced the closing of our Gulf Coast business unit office in Houston, Texas, effective November 1, 2009. The operations will be combined with and operated out of our Southwestern Area office in Fort Worth. 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 the consolidated statement of operations caption called “Derivative fair value income (loss).” The following table summarizes the primary components of oil and gas sales for the three months and the nine months ended September 30, 2009 and 2008 (in thousands):

		Three Months Ended																Nine Months Ended
		September 30,																September 30,
		2009				2008				Change				%				2009				2008				Change				%
Oil wellhead		$	33,869			$	86,506			$	(52,637	)			(61	%)		$	101,892			$	257,640			$	(155,748	)			(60	%)
Oil hedges realized			240				(28,003	)			28,243				101	%			12,247				(76,428	)			88,675				116	%
Total oil sales			34,109				58,503				(24,394	)			(42	%)			114,139				181,212				(67,073	)			(37	%)
Gas wellhead			97,004				282,243				(185,239	)			(66	%)			300,646				775,813				(475,167	)			(61	%)
Gas hedges realized			54,122				(13,188	)			67,310				510	%			146,594				(9,540	)			156,134				1,637	%
Total gas sales			151,126				269,055				(117,929	)			(44	%)			447,240				766,273				(319,033	)			(42	%)
NGL			16,887				20,162				(3,275	)			(16	%)			36,455				55,241				(18,786	)			(34	%)
Combined wellhead			147,760				388,911				(241,151	)			(62	%)			438,993				1,088,694				(649,701	)			(60	%)
Combined hedges			54,362				(41,191	)			95,553				232	%			158,841				(85,968	)			244,809				285	%
Total oil and gas sales		$	202,122			$	347,720			$	(145,598	)			(42	%)		$	597,834			$	1,002,726			$	(404,892	)			(40	%)