(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

(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)

(817) 870-2601
(Registrant’s Telephone Number, Including Area Code)

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 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. (Check one):

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

155,335,630 Common Shares were outstanding on October 21, 2008.

 

 

     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.

				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		21
Item 3.		Quantitative and Qualitative Disclosures about Market Risk		32
Item 4.		Controls and Procedures		33
PART II — OTHER INFORMATION
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		34
Item 6.		Exhibits		35
EX-31.1
EX-31.2
EX-32.1
EX-32.2

		September 30,				December 31,
		2008				2007
		(Unaudited)
Assets
Current assets:
Cash and equivalents		$	265			$	4,018
Accounts receivable, less allowance for doubtful accounts of $813 and $583			246,682				166,484
Unrealized derivative gain			23,958				53,018
Deferred tax asset			28,582				26,907
Inventory and other			15,869				11,387
Total current assets			315,356				261,814
Unrealized derivative gain			1,903				1,082
Equity method investments			140,394				113,722
Oil and gas properties, successful efforts method			5,787,886				4,443,577
Accumulated depletion and depreciation			(1,115,905	)			(939,769	)
			4,671,981				3,503,808
Transportation and field assets			121,426				104,802
Accumulated depreciation and amortization			(53,189	)			(43,676	)
			68,237				61,126
Other assets			73,323				74,956
Total assets		$	5,271,194			$	4,016,508
Liabilities
Current liabilities:
Accounts payable		$	301,992			$	212,514
Asset retirement obligations			1,827				1,903
Accrued liabilities			49,546				42,964
Accrued interest			28,270				17,595
Unrealized derivative loss			40,853				30,457
Total current liabilities			422,488				305,433
Bank debt			550,000				303,500
Subordinated notes			1,097,459				847,158
Deferred tax, net			744,070				590,786
Unrealized derivative loss			19,609				45,819
Deferred compensation liability			112,459				120,223
Asset retirement obligations and other liabilities
Commitments and contingencies			71,156				75,567
Stockholders’ equity
Preferred stock, $1 par, 10,000,000 shares authorized, none outstanding			—				—
Common stock, $.01 par, 475,000,000 shares authorized, 155,225,667 issued at September 30, 2008 and 149,667,497 issued at December 31, 2007			1,552				1,497
Common stock held in treasury — 233,900 shares at September 30, 2008 and 155,500 shares at December 31, 2007			(8,557	)			(5,334	)
Additional paid-in capital			1,687,675				1,386,884
Retained earnings			604,604				371,800
Accumulated other comprehensive loss			(31,321	)			(26,825	)
Total stockholders’ equity			2,253,953				1,728,022
Total liabilities and stockholders’ equity		$	5,271,194			$	4,016,508

RANGE RESOURCES CORPORATION

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Revenues
Oil and gas sales		$	347,720			$	214,424			$	1,002,726			$	621,636
Transportation and gathering			1,537				508				3,890				1,203
Derivative fair value income (loss)			272,869				24,974				(49,308	)			11,120
Other			544				2,447				20,777				4,749
Total revenues			622,670				242,353				978,085				638,708
Costs and expenses
Direct operating			36,532				28,003				106,710				78,233
Production and ad valorem taxes			15,210				11,316				45,106				32,958
Exploration			19,149				6,233				55,204				29,668
General and administrative			24,650				18,058				66,000				50,574
Deferred compensation plan			(37,515	)			7,761				(9,365	)			28,342
Interest expense			25,373				19,935				72,361				56,356
Depletion, depreciation and amortization			81,173				57,001				230,206				155,798
Total costs and expenses			164,572				148,307				566,222				431,929
Income from continuing operations before income taxes			458,098				94,046				411,863				206,779
Income tax provision
Current			2,374				133				4,209				416
Deferred			170,400				34,802				155,172				73,698
			172,774				34,935				159,381				74,114
Income from continuing operations			285,324				59,111				252,482				132,665
Discontinued operations, net of taxes			—				(196	)			—				63,593
Net income		$	285,324			$	58,915			$	252,482			$	196,258
Earnings per common share:
Basic — income from continuing operations		$	1.87			$	0.40			$	1.68			$	0.92
— discontinued operations			—				—				—				0.45
— net income		$	1.87			$	0.40			$	1.68			$	1.37
Diluted — income from continuing operations		$	1.81			$	0.39			$	1.62			$	0.89
— discontinued operations			—				—				—				0.43
— net income		$	1.81			$	0.39			$	1.62			$	1.32
Dividends per common share		$	0.04			$	0.03			$	0.12			$	0.09

See accompanying notes.

RANGE RESOURCES CORPORATION

		Nine Months Ended
		September 30,
		2008				2007
Operating activities:
Net income		$	252,482			$	196,258
Adjustments to reconcile to net cash provided from operating activities:
Income from discontinued operations			—				(63,593	)
Income from equity method investments			(170	)			(1,280	)
Deferred income tax expense			155,172				73,698
Depletion, depreciation and amortization			230,206				155,798
Unrealized derivative gains			(1,862	)			(502	)
Mark-to-market losses on oil and gas derivatives not designated as hedges			4,910				40,171
Exploration dry hole costs			9,337				9,072
Amortization of deferred financing costs and other			2,137				1,667
Deferred and stock-based compensation			13,413				46,770
(Gain) loss on sale of assets and other			(19,415	)			2,247
Changes in working capital:
Accounts receivable			(64,468	)			(29,595	)
Inventory and other			(5,263	)			(1,672	)
Accounts payable			2,927				11,597
Accrued liabilities and other			20,982				4,894
Net cash provided from continuing operations			600,388				445,530
Net cash provided from discontinued operations			—				10,189
Net cash provided from operating activities			600,388				455,719
Investing activities:
Additions to oil and gas properties			(646,403	)			(601,046	)
Additions to field service assets			(20,651	)			(20,318	)
Acquisitions, net of cash acquired			(733,767	)			(309,660	)
Investing activities of discontinued operations			—				(7,375	)
Additional investment in other assets			(50,956	)			(93,313	)
Proceeds from disposal of assets and other			66,693				234,329
Purchases of marketable securities held by the deferred compensation plan			(9,300	)			(34,724	)
Proceeds from the sale of marketable securities held by the deferred compensation plan			6,605				33,823
Net cash used in investing activities			(1,387,779	)			(798,284	)
Financing activities:
Borrowings on credit facility			1,219,000				718,000
Repayments on credit facility			(972,500	)			(904,000	)
Debt issuance costs			(5,710	)			(2,727	)
Dividends paid			(18,404	)			(13,098	)
Issuance of subordinated notes			250,000				250,000
Issuance of common stock			288,643				292,753
Treasury stock purchases			(3,223	)			(5,334	)
Purchases of common stock held by the deferred compensation plan			(88	)			(69	)
Proceeds from the sale of common stock held by the deferred compensation plan			5,135				3,291
Cash overdrafts			20,785				1,554
Net cash provided from financing activities			783,638				340,370
Net decrease in cash and equivalents			(3,753	)			(2,195	)
Cash and equivalents at beginning of period			4,018				2,382
Cash and equivalents at end of period		$	265			$	187

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Net income		$	285,324			$	58,915			$	252,482			$	196,258
Other comprehensive (loss) income:
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive (loss) income			25,670				(2,592	)			53,299				(8,863	)
Change in unrealized deferred hedging gains (losses)			222,436				3,836				(59,069	)			(16,295	)
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes			—				491				—				1,611
Total comprehensive income		$	533,430			$	60,650			$	246,712			$	172,711

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, Appalachian and Gulf Coast 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 whose common stock is 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 Corporation 2007 Annual Report on Form 10-K filed on February 27, 2008. 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.

     During the first quarter of 2007, we sold our interests in our Austin Chalk properties that we purchased as part of our June 2006 acquisition of Stroud Energy, Inc. (“Stroud”). We also sold our Gulf of Mexico properties at the end of first quarter 2007. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we have reflected the results of operations of the above divestitures as discontinued operations, rather than a component of continuing operations. See Note 5 for additional information regarding discontinued operations.

(3) NEW ACCOUNTING STANDARDS

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. We adopted SFAS No. 157 effective January 1, 2008 and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows. See Note 12 for other disclosures required by SFAS No. 157. In February 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of 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 of SFAS No. 157 primarily applies to our asset retirement obligation (ARO), which uses fair value measures at the date incurred to determine our liability. We are currently evaluating the impact of the pending adoption in 2009 of SFAS No. 157 non-recurring fair value measures.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income or loss. The statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. We adopted SFAS No. 159 effective January 1, 2008 and the impact of the adoption resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our investment securities held in our deferred compensation plan from accumulated other comprehensive loss to retained earnings. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. All investment securities held in our deferred compensation plans are reported in the balance sheet category called other assets and total $41.8 million at September 30, 2008 compared to $51.5 million at December 31, 2007. As of January 1, 2008, all of these investment securities are accounted for using the mark-to-market accounting method, are classified as trading securities and all subsequent changes to fair value will be included in our statement of operations. For these securities, interest and dividends and mark-to-market gains or losses are included in the income statement category called deferred compensation plan expense. For third quarter 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, 2008, interest and dividends were $319,000 and the mark-to-market was a loss of $11.5 million. See Note 12 for other disclosures required by SFAS No. 159.

(4) ACQUISITIONS AND DISPOSITIONS

Acquisitions

     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in our consolidated statements of operations from the closing date of acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.

     In the third quarter of 2008, we acquired Marcellus Shale unproved properties in a transaction for approximately $210.0 million, subject to typical post-closing adjustments. In the first six months of 2008, we completed several acquisitions of Barnett Shale producing and unproved properties for $331.8 million. After recording asset retirement obligations and transaction costs of $817,000, the purchase price allocated to proved properties was $232.8 million and unproved properties was $99.7 million.

Dispositions

     In first quarter 2008, we sold East Texas properties for proceeds of $64.4 million and recorded a gain of $20.1 million. In first quarter 2007, we sold Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. In first quarter 2007, we also sold Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on the sale of $95.1 million. We have reflected the results of operations of the Austin Chalk and Gulf of Mexico divestitures as discontinued operations rather than a component of continuing operations for 2007. See Note 5 for additional information.

(5) DISCONTINUED OPERATIONS

     As part of our Stroud acquisition in 2006, we purchased Austin Chalk properties, which we sold in first quarter 2007 for proceeds of $80.4 million. In first quarter 2007, we also sold our Gulf of Mexico properties for proceeds of $155.0 million. Discontinued operations for the three months and the nine months ended September 30, 2007 are summarized as follows (in thousands):

		Three Months				Nine Months
		Ended				Ended
		September 30,				September 30,
		2007				2007
Revenues:
Oil and gas sales		$	—			$	15,187
Transportation and gathering			—				10
Other			—				310
(Loss) gain on disposition of assets and other			(298	)			92,757
			(298	)			108,264
Costs and expenses:
Direct operating			—				2,559
Production and ad valorem taxes			—				141
Exploration and other			3				215
Interest expense			—				845
Depletion, depreciation and amortization			—				6,672
			3				10,432
(Loss) income from discontinued operations before income taxes			(301	)			97,832
Income tax (benefit) expense			(105	)			34,239
(Loss) income from discontinued operations, net of taxes		$	(196	)		$	63,593
Production:
Crude oil (bbls)			—				40,634
Natural gas (mcf)			—				1,990,277
Total (mcfe)			—				2,234,081

(6) INCOME TAXES

     Income tax included in continuing operations was as follows (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Income tax expense		$	172,774			$	34,935			$	159,381			$	74,114
Effective tax rate			37.7	%			37.1	%			38.7	%			35.8	%

     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, 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, 2008 and September 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. For the nine months ended September 30, 2008, our overall effective tax rate for continuing operations was different than the statutory rate of 35% due to state income taxes, and $2.6 million additional expense for discrete items. For the nine months ended September 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. We expect our effective tax rate to be approximately 38% for the remainder of 2008.

     At December 31, 2007, we had regular tax net operating loss (“NOL”) carryforwards of $204.4 million and alternative minimum tax (“AMT”) NOL carryforwards of $149.7 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2007 was $39.7 million, net of the SFAS No. 123(R) deduction for unrealized benefits. We have $26.9 million of NOLs generated in years before 1998, which are subject to yearly limitations due to IRC Section 382. We do not believe the application of the Section 382 limitations hinders our ability to use such NOLs and therefore, no valuation allowance has been provided. At December 31, 2007, we had AMT credit carryforwards of $777,000 that are not subject to limitation or expiration. We expect to make AMT estimated tax payments of $1.0 million in 2008 and utilize approximately $38.0 million in regular NOL carryforwards and $45.0 million of AMT NOL carryforwards during 2008.

(7) EARNINGS PER COMMON SHARE

     Basic income per share is based on weighted average number of common shares outstanding. Diluted income per share includes exercise of stock options, stock appreciation rights and restricted shares, 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								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Numerator:
Income from continuing operations		$	285,324			$	59,111			$	252,482			$	132,665
Income from discontinued operations, net of taxes			—				(196	)			—				63,593
Net income		$	285,324			$	58,915			$	252,482			$	196,258
Denominator:
Weighted average common shares outstanding — basic			152,765				147,182				150,487				143,508
Effect of dilutive securities:
Employee stock options, SARs and stock held in the deferred compensation plan			4,964				5,209				5,409				5,163
Weighted average common shares — diluted			157,729				152,391				155,896				148,671
Earnings per common share:
Basic — income from continuing operations		$	1.87			$	0.40			$	1.68			$	0.92
— discontinued operations			—				—				—				0.45
— net income			1.87				0.40				1.68				1.37
Diluted — income from continuing operations		$	1.81			$	0.39			$	1.62			$	0.89
— discontinued operations			—				—				—				0.43
— net income			1.81				0.39				1.62				1.32

     The weighted average common shares — basic amount excludes 2.2 million shares at September 30, 2008 and 2.0 million shares at September 30, 2007, of restricted stock that is held in our deferred compensation plan (although all restricted stock is issued and outstanding upon grant). Stock appreciation rights, or SARs, 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. SARs for 544,000 shares for the three months ended September 30, 2007 and 282,000 shares for the nine months ended September 30, 2007 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.

(8) SUSPENDED EXPLORATORY WELL COSTS

     The following table reflects the changes in capitalized exploratory well costs for the nine months ended September 30, 2008 and the year ended December 31, 2007 (in thousands):

		September 30,				December 31,
		2008				2007
Beginning balance at January 1		$	15,053			$	9,984
Additions to capitalized exploratory well costs pending the determination of proved reserves			29,319				14,428
Reclassifications to wells, facilities and equipment based on determination of proved reserves			(3,837	)			—
Capitalized exploratory well costs charged to expense			(3,598	)			(8,034	)
Divested wells			—				(1,325	)
Balance at end of period			36,937				15,053
Less exploratory well costs that have been capitalized for a period of one year or less			(32,007	)			(12,067	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$	4,930			$	2,986
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			3				2

     The $36.9 million of capitalized exploratory well costs at September 30, 2008 was incurred in 2008 ($27.0 million), in 2007 ($7.0 million) and in 2006 ($2.9 million).

(9) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at September 30, 2008 is shown parenthetically). No interest expense was capitalized during the three or the nine months ended September 30, 2008 and 2007.

		September 30,				December 31,
		2008				2007
Bank debt (4.0%)		$	550,000			$	303,500
Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount			197,874				197,602
6.375% Senior Subordinated Notes due 2015			150,000				150,000
7.5% Senior Subordinated Notes due 2016, net of discount			249,585				249,556
7.5% Senior Subordinated Notes due 2017			250,000				250,000
7.25% Senior Subordinated Notes due 2018			250,000				—
Total debt		$	1,647,459			$	1,150,658

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 $1.0 billion facility amount or the borrowing base. On September 30, 2008, the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. On October 7, 2008, our borrowing base was reconfirmed at $1.5 billion. Our current bank group is comprised of twenty-four commercial banks each holding between 3.0% and 5.3% of the total facility. Of those twenty-four banks, twelve are domestic banks and twelve are foreign banks or wholly owned subsidiaries of foreign banks. The fourth amendment to our credit facility was filed as an exhibit to our Quarterly Report on Form 10-Q filed with the SEC on April 23, 2008. 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, 2008, the outstanding balance under the bank credit facility was $550.0 million and there was $450.0 million of committed borrowing capacity and an additional $500.0 million of uncommitted borrowing base capacity available. The loan matures October 25, 2012. Borrowing under the bank credit

facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such data plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.0% to 0.5% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. On all LIBOR loans, we pay a varying rate per annum equal to the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.0% and 1.75% per annum depending on the total outstanding under the bank credit facility 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 4.3% for the three months ended September 30, 2008 compared to 6.5% for the three months ended September 30, 2007. The weighted average interest rate on the bank credit facility for the nine months ended September 30, 2008 was 4.7% compared to 6.5% in the same period of the prior year. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At September 30, 2008, the commitment fee was 0.25% and the interest rate margin was 1.0%. At October 21, 2008, the interest rate (including applicable margin) was 4.5%.

Senior Subordinated Notes

     In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). Interest on the 7.25% Notes is payable semi-annually, in May and November, and is guaranteed by certain of our subsidiaries. We may redeem the 7.25% Notes, in whole or in part, at any time on or after May 1, 2013, at redemption prices of 103.625% of the principal amount as of May 1, 2013 and declining to 100.0% on May 1, 2016 and thereafter. Before May 1, 2011, we may redeem up to 35% of the original aggregate principal amount of the 7.25% Notes at a redemption price equal to 107.25% 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 7.25% 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, 2008.

     The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical 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, 2008, we were in compliance with these covenants.

(10) 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. A reconciliation of our liability for plugging, abandonment and remediation costs for the nine months ended September 30, 2008 is as follows (in thousands):

		Nine Months Ended
		September 30,
		2008
Beginning of period		$	75,308
Liabilities incurred			2,359
Liabilities settled			(851	)
Disposition of wells			(898	)
Accretion expense			4,064
Change in estimate			(9,420	)
End of period		$	70,562

     Accretion expense is recognized as a component of depreciation, depletion and amortization. The change in estimate category for the nine months ended September 30, 2008 is primarily due to a change in certain of our estimated plugging dates.

     In May 2008, at our annual meeting, our shareholders approved an increase to our number of authorized shares of common stock. We now 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 2007:

		Nine				Year
		Months Ended				Ended
		September 30,				December 31,
		2008				2007
Beginning balance			149,667,497				138,931,565
Public offering			4,435,300				8,050,000
Stock options/SARs exercised			955,816				2,220,627
Restricted stock grants			167,054				408,067
In lieu of bonuses			—				29,483
Contributed to 401(k) plan			—				27,755
Treasury shares			(78,400	)			—
			5,479,770				10,735,932
Ending balance			155,147,267				149,667,497

     In May 2008, we completed a public offering of 4.4 million shares of common stock at $66.38 per share. After underwriting discount and other offering costs of $12.5 million, net proceeds of $281.9 million were used to repay indebtedness on our bank credit facility.

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. In the third quarter 2008, we repurchased 78,400 shares of common stock at an average price of $41.11 per share for a total of $3.2 million.

     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, 2008, we had open swap contracts covering 39.8 Bcf of gas at prices averaging $8.66 per mcf. We also had collars covering 61.2 Bcf of gas at weighted average floor and cap prices of $8.26 to $9.40 per mcf and 3.7 million barrels of oil at weighted average floor and cap prices of $62.98 to $75.89 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, 2008, was a net unrealized pre-tax loss of $47.1 million. These contracts expire monthly through December 2009.

     The following table sets forth our derivative volumes by year as of September 30, 2008:

Average

Period

Contract Type

Volume Hedged

Hedge Price

Natural Gas

2008

Swaps

155,000 Mmbtu/day

$ 9.17

2008

Collars

70,000 Mmbtu/day

$ 8.10 — $10.50

2009

Swaps

70,000 Mmbtu/day

$ 8.38

2009

Collars

150,000 Mmbtu/day

$ 8.28 — $9.27

Crude Oil

2008

Collars

9,000 bbl/day

$ 59.34 — $75.48

2009

Collars

8,000 bbl/day

$ 64.01 — $76.00

     Under SFAS No. 133, every derivative instrument is required to be 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 loss, which is later transferred to earnings when the hedged transaction occurs. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized in earnings. As of September 30, 2008, an unrealized pre-tax derivative loss of $50.4 million was recorded in the balance sheet caption accumulated other comprehensive loss. This loss is expected to be reclassified into earnings in 2008 ($4.4 million) and 2009 ($46.0 million). 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 $41.2 million and $86.0 million of losses in the three months and the nine months ended September 30, 2008 compared to gains of $4.1 million and $14.1 million in the three months and the nine months ended September 30, 2007. Any ineffectiveness associated with these hedges is reflected in the income statement caption 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 nine months ended September 30, 2008 includes ineffective unrealized gains of $1.9 million compared to gains of $502,000 in the same period of 2007.

     Some of our derivatives do not qualify for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. 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 income statement caption called derivative fair value income (loss) (see table below). As a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of our derivatives, which was designated to our Gulf Coast production, is marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges to market due to the anticipated sale of a portion of our East Texas properties, which was sold in first quarter 2008.

     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 gain of $12.5 million at September 30, 2008 and these swaps expire in 2010.

     The following table presents information about the components of derivative fair value income (loss) in the three months and the nine months ended September 30, 2008 and 2007 (in thousands):

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Hedge ineffectiveness — realized		$	(213	)		$	—			$	2			$	—
— unrealized			4,553				(28	)			1,862				502
Change in fair value of derivatives that do not qualify for hedge accounting			294,317				5,618				(4,910	)			(40,171	)
Realized (loss) gain on settlements — gas (a)			(18,520	)			19,417				(30,192	)			50,818
Realized loss on settlements — oil (a)			(7,268	)			(33	)			(16,070	)			(29	)
Derivative fair value income (loss)		$	272,869			$	24,974			$	(49,308	)		$	11,120

     The combined fair value of derivatives included in our consolidated balance sheets as of September 30, 2008 and December 31, 2007 is summarized below (in thousands). We conduct derivative activities with fourteen 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. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty. For example, as of September 30, 2008, we have two counterparties with a total derivative position equal to a net receivable of $16.2 million. This receivable includes an oil collar payable of $10.0 million, which is netted and reported in our derivative receivable.

		September 30,				December 31,
		2008				2007
Derivative assets:
Natural gas — swaps		$	18,923			$	54,577
— collars			12,582				4,916
— basis swaps			4,338				1,082
Crude oil — collars			(9,982	)			(6,475	)
		$	25,861			$	54,100
Derivative liabilities:
Natural gas — swaps		$	9,742			$	6,594
— collars			15,050				11,302
— basis swaps			8,125				(937	)
Crude oil — collars			(93,379	)			(93,235	)
		$	(60,462	)		$	(76,276	)

     Effective January 1, 2008, we adopted SFAS No. 157, as discussed in Note 3, which among other things, requires enhanced disclosures about assets and liabilities carried at fair value. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which include multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset.

     SFAS No. 157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among techniques. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and lowest priority to unobservable inputs (level 3 measurements). The three levels of fair value hierarchy defined by SFAS No. 157 are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2 — Pricing inputs are other than quoted prices in active markets included in either Level 1, which are directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data, which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At September 30, 2008, we have no Level 3 measurements.

     We use a market approach for our fair value measurements. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis, as set forth in SFAS No. 157 (in thousands):

						Fair Value Measurements at September 30, 2008 Using
						Quoted Prices in				Significant Other				Significant
		Total Carrying				Active Markets for				Observable				Unobservable
		Value as of				Identical Assets				Inputs				Inputs
		September 30, 2008				(Level 1)				(Level 2)				(Level 3)
Trading securities held in the deferred compensation plans		$	41,800			$	41,800			$	—			$	—
Derivatives — swaps			28,665				—				28,665				—
— collars			(75,729	)			—				(75,729	)			—
— basis swaps			12,463				—				12,463				—

     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, 2008 market values. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services to corroborate market data.

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 $813,000 at September 30, 2008 and $583,000 at December 31, 2007. 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 fourteen financial institutions, twelve 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, 2008, our net derivative liability includes a receivable from J. Aron & Company of $618,000 and a liability to Mitsui & Co. for $15.3 million.

     We are a creditor in the bankruptcy of SemGroup, L.P. and certain of its subsidiaries, or SemGroup, which filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code in July 2008. SemGroup purchased oil from us and is currently indebted to us for approximately $1.0 million. We believe that it is probable that a portion of this receivable is uncollectible and have recognized a $450,000 charge in earnings in third quarter 2008.

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

     We have six equity-based stock plans, of which two are active. Under the active 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 outside, independent directors from the Board of Directors. All awards granted have been issued at prevailing market prices at the time of the grant. Information with respect to stock option and SARs activities is summarized below:

						Weighted
						Average
						Exercise
		Shares				Price
Outstanding on December 31, 2007			7,772,325			$	17.95
Granted			1,142,770				63.61
Exercised			(1,201,502	)			14.22
Expired/forfeited			(72,833	)			41.55
Outstanding on September 30, 2008			7,640,760			$	25.14

     The following table shows information with respect to outstanding stock options and SARs at September 30, 2008:

			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			1,870,694				1.94			$	4.71				1,870,694			$	4.71
	10.00 —   19.99			1,888,667				1.58				16.25				1,888,667				16.25
	20.00 —   29.99			1,303,586				2.50				24.37				714,836				24.26
	30.00 —   39.99			1,449,403				3.49				33.98				406,953				34.64
	40.00 —   49.99			26,130				4.34				42.60				960				40.54
	50.00 —   59.99			727,115				4.37				58.57				180				58.60
	60.00 —   69.99			28,427				4.62				65.33				—				—
	70.00 —   75.00			346,738				4.64				75.00				26,484				75.00
		Total		7,640,760				2.61			$	25.14				4,908,774			$	14.87

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2008 was $20.65. The fair value of each stock option/SAR granted during 2008 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 2.41%; dividend yield of 0.26%; expected volatility of 41%; and an expected life of 3.5 years.

     As of September 30, 2008, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $158.7 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $138.3 million and 2.03 years. As of September 30, 2008, 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 were $24.64 and 2.6 years and the aggregate intrinsic value was $158.0 million. As of September 30, 2008, unrecognized compensation cost related to the awards was $26.9 million, which is expected to be recognized over a weighted average period of 1.1 years. Of the 7.6 million stock option/SARs outstanding at September 30, 2008, 2.9 million are stock options and 4.7 million are SARs.

     During the first nine months of 2008, 314,000 shares of restricted stock (or non-vested shares) were issued 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. In the first nine months of 2007, we issued 413,000 shares of restricted stock as compensation to employees at an average price of $34.62 with a three year vesting period and 15,900 shares were granted to our directors at a price of $38.02 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 $10.7 million in the first nine months of 2008 compared to $6.4 million in the nine-month period ended September 30, 2007. As of September 30, 2008, unrecognized compensation cost related to restricted stock awards was $26.7 million, which is expected to be recognized over the next 3 years (excluding mark-to-market that would also be recognized over that same time period). All of our restricted stock grants are held in our deferred compensation plans (see discussion below). The vesting of these shares is based upon an employees’ continued employment with us.

     A summary of the status of our non-vested restricted stock outstanding at September 30, 2008 is presented below:

						Weighted
						Average Grant
		Shares				Date Fair Value
Non-vested shares outstanding at December 31, 2007			563,660			$	30.42
Granted			324,949				65.72
Vested			(322,402	)			37.39
Forfeited			(7,908	)			43.32
Non-vested shares outstanding at September 30, 2008			558,299			$	46.75

     In December 2004, we adopted the Range Resources Corporation Deferred Compensation Plan (“2005 Deferred Compensation Plan”). The 2005 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 rabbi 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 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 in 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 stock held in the Rabbi Trust. We recorded non-cash, mark-to-market income related to our deferred compensation plan of $37.5 million in the third quarter 2008 and $9.4 million in the first nine months of 2008 compared to mark-to-market expense of $7.8 million and $28.3 million in the same periods of 2007.

		Nine Months Ended
		September 30,
		2008				2007
		(in thousands)
Non-cash investing and financing activities included:
Asset retirement costs capitalized		$	(7,389	)		$	(438	)
Net cash provided from operating activities included:
Income taxes paid		$	4,554			$	144
Interest paid			59,590				56,657

     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, 2008, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):

2008			$1,729
2009			7,507
2010			6,760
2011			8,000
2012			5,802
Thereafter			8,717

     In 2008, we entered into a fifteen-year agreement with a third party to provide gathering, compression and liquids processing in southwestern Pennsylvania. These facilities are expected to process and transport the majority of gas produced by us from wells drilled in the southwestern Pennsylvania area of the Marcellus Shale. The potential effect on future commitments is not included in the table above since our commitments are contingent upon completion of the facilities and throughput volumes. It is estimated that initial throughput capacity will be 30,000 Mmbtu per day. Expansions of the facility are anticipated in the future to substantially enhance this capacity.

     In addition to amounts included in the above table, we have committed to a further delivery of additional gas volumes to a gas pipeline in southwestern Pennsylvania. This commitment is scheduled to increase in increments of 30,000 Mmbtu per day in April 2009 and July 2009 and increase an additional 42,000 Mmbtu per day in January 2010 through 2014. These increases are contingent on certain pipeline modifications being completed.

     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.

		September 30,				December 31,
		2008				2007
		(in thousands)
Oil and gas properties:
Properties subject to depletion		$	5,025,970			$	4,172,151
Unproved properties			761,916				271,426
Total			5,787,886				4,443,577
Accumulated depreciation, depletion and amortization			(1,115,905	)			(939,769	)
Net capitalized costs		$	4,671,981			$	3,503,808

		Nine Months
		Ended				Year Ended
		September 30,				December 31,
		2008				2007
		(in thousands)
Acquisitions:
Unproved leasehold		$	100,398			$	4,552
Proved oil and gas properties			233,557				253,064
Asset retirement obligations			251				3,301
Acreage purchases (b)			434,792				78,095
Development			572,407				734,987
Exploration:
Drilling			84,735				40,567
Expense			52,076				39,872
Stock-based compensation expense			3,128				3,473
Gas gathering facilities			25,248				18,655
Subtotal			1,506,592				1,176,566
Asset retirement obligations			(7,389	)			(7,075	)
Total costs incurred		$	1,499,203			$	1,169,491

(18) ACCOUNTING STANDARDS NOT YET ADOPTED

     In June 2008, the FASB issued Staff Position No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (“FSP EITF 03-6-1”) 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. FSP EITF 03-6-1 is effective for us on January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retroactively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this definition, we do not expect the application of FSP 03-6-1 to have a significant impact on our reported earnings per share.

     In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. This statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect the adoption of SFAS No. 162 to have an impact on our financial statements.

     In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.” SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for us on January 1, 2009 and will only impact future disclosures about our derivative instruments and hedging activities.

     In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement 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 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 statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. We are currently evaluating provisions of this statement.

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 2007 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 2007 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate only to our continuing operations.

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. There have been no significant changes to our critical accounting estimates or policies subsequent to December 31, 2007.

Results of Continuing Operations

Overview

     Total revenues increased $380.3 million, or 157% for third quarter 2008 over the same period of 2007. The increase includes a $133.3 million, or 62% increase in oil and gas sales and a $247.9 million increase in derivative fair value income. Oil and gas sales vary due to changes in volumes of production sold and realized commodity prices. For third quarter 2008, production increased 19% from the same period of the prior year with the continued success of our drilling program and our acquisitions. Realized prices were higher by 16% in third quarter 2008 when compared to third quarter 2007. We believe oil and gas prices will continue to remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy and the level of oil and gas production in North America and worldwide.

     All of our expenses increased on both an absolute and per mcfe basis during the third quarter 2008, when compared to the same period of 2007, due to higher overall industry costs, higher compensation expense resulting from additional employees, increased salaries and higher levels of activity. While overall costs were higher, the rate of inflation experienced in our industry appears to have moderated for some goods and services. The availability of goods and services continues to be mixed. We continue to experience significant competition for technical and experienced personnel and overall compensation inflation in our industry continues to be high. It is difficult for us to forecast price trends, supply, service or personnel availability, any of which, if changed in an adverse manner would significantly impact both operating costs and capital expenditures. As we continue to have Marcellus wells shut-in waiting on pipeline and processing facilities and we continue to expand our Marcellus operating team to meet the needs of this developing asset, we expect to see continued upward pressure on our cost structure. The initial phase of the pipeline and processing infrastructure is expected to be completed in fourth quarter 2008 with additional expansions set for 2009 and later.

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 or 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 income statement 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, 2008 and 2007 (in thousands):

		Three Months Ended																Nine Months Ended
		September 30,																September 30,
		2008				2007				Change				%				2008				2007				Change				%
Oil wellhead		$	86,506			$	59,218			$	27,288				46	%		$	257,640			$	161,019			$	96,621				60	%
Oil hedges realized			(28,003	)			(5,120	)			(22,883	)			447	%			(76,428	)			(7,068	)			(69,360	)			981	%
Total oil revenue			58,503				54,098				4,405				8	%			181,212				153,951				27,261				18	%
Gas wellhead			282,243				138,832				143,411				103	%			775,813				414,758				361,055				87	%
Gas hedges realized			(13,188	)			9,235				(22,423	)			243	%			(9,540	)			21,136				(30,676	)			145	%
Total gas revenue			269,055				148,067				120,988				82	%			766,273				435,894				330,379				76	%
NGL			20,162				12,259				7,903				64	%			55,241				31,791				23,450				74	%
Combined wellhead			388,911				210,309				178,602				85	%			1,088,694				607,568				481,126				79	%
Combined hedges			(41,191	)			4,115				(45,306	)			1,101	%			(85,968	)			14,068				(100,036	)			711	%
Total oil and gas sales		$	347,720			$	214,424			$	133,296				62	%		$	1,002,726			$	621,636			$	381,090				61	%

     Our production continues to grow through continued drilling success as we place new wells into production and additions from acquisitions. For third quarter 2008, our production volumes increased, from the same period of the prior year, 85% in our Gulf Coast Area, 20% in our Southwestern Area and 13% in our Appalachian Area. For the nine months ended September 30, 2008, our production volumes increased, when compared to the prior year, 75% in our Gulf Coast Area, 22% in our Southwestern Area and 20% in our Appalachian Area. Our production for the three months and the nine months ended September 30, 2008 and 2007 is shown below:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Production:
Crude oil (bbls)			759,449				839,863				2,343,138				2,559,992
NGLs (bbls)			345,635				284,088				993,366				837,625
Natural gas (mcf)			29,053,832				23,261,704				84,029,611				64,469,734
Total (mcfe) (a)			35,684,336				30,005,410				104,048,635				84,855,436
Average daily production:
Crude oil (bbls)			8,255				9,129				8,552				9,377
NGLs (bbls)			3,757				3,088				3,625				3,068
Natural gas (mcf)			315,803				252,845				306,677				236,153
Total (mcfe) (a)			387,873				326,146				379,740				310,826

     Our average realized price (including all derivative settlements) received for oil and gas was $9.02 per mcfe in third quarter 2008 compared to $7.79 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 and the nine months ended September 30, 2008 and 2007 are shown below:

		Three Months Ended								Nine Months Ended,
		September 30,								September 30,
		2008				2007				2008				2007
Average sales prices (wellhead):
Crude oil (per bbl)		$	113.91			$	70.51			$	109.95			$	62.90
NGLs (per bbl)		$	58.34			$	43.15			$	55.61			$	37.95
Natural gas (per mcf)		$	9.72			$	5.97			$	9.23			$	6.43
Total (per mcfe) (a)		$	10.90			$	7.01			$	10.46			$	7.16
Average realized price (including derivatives that qualify for hedge accounting):
Crude oil (per bbl)		$	77.03			$	64.41			$	77.34			$	60.14
NGLs (per bbl)		$	58.34			$	43.15			$	55.61			$	37.95
Natural gas (per mcf)		$	9.26			$	6.37			$	9.12			$	6.76
Total (per mcfe) (a)		$	9.74			$	7.15			$	9.64			$	7.33
Average realized price (including all derivative settlements):
Crude oil (per bbl)		$	67.40			$	64.37			$	70.06			$	60.13
NGLs (per bbl)		$	58.34			$	43.15			$	55.61			$	37.95
Natural gas (per mcf)		$	8.62			$	7.20			$	8.77			$	7.55
Total (per mcfe) (a)		$	9.02			$	7.79			$	9.19			$	7.92
Average NYMEX prices (b)
Oil (per bbl)		$	117.83			$	75.38			$	113.66			$	66.23
Natural gas (per mcf)		$	10.08			$	6.13			$	9.67			$	6.88