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

For the quarterly period ended March 31, 2008

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

For the transition period from                      to                     

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

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

150,314,399 Common Shares were outstanding on April 21, 2008.

 

 

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

TABLE OF CONTENTS

						Page
PART I — FINANCIAL INFORMATION
		Item 1.		Financial Statements:
				Consolidated Balance Sheets			3
				Consolidated Statements of Operations (unaudited)			4
				Consolidated Statements of Cash Flows (unaudited)			5
				Consolidated Statements of Comprehensive Income (Loss) (unaudited)			6
				Notes to Consolidated Financial Statements (unaudited)			7
		Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
		Item 3.		Quantitative and Qualitative Disclosures about Market Risk			27
		Item 4.		Controls and Procedures			28
PART II — OTHER INFORMATION
		Item 6.		Exhibits			29
Fourth Amendment to the Third Amended and Restated Credit Agreement
Certification by the President and Chief Executive Officer Pursuant to Section 302
Certification by the Chief Financial Officer Pursuant to Section 302
Certification by the President and Chief Executive Officer Pursuant to Section 906
Certification by the Chief Financial Officer Pursuant to Section 906

PART I — Financial Information

ITEM 1. — Financial Statements

RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)

		March 31,				December 31,
		2008				2007
		(Unaudited)
Assets:
Current assets:
Cash and equivalents		$	90			$	4,018
Accounts receivable, less allowance for doubtful accounts of $477 and $583			195,013				166,484
Unrealized derivative gain			—				53,018
Deferred tax asset			68,549				26,907
Inventory and other			9,381				11,387
Total current assets			273,033				261,814
Unrealized derivative gain			2,244				1,082
Equity method investments			114,766				113,722
Oil and gas properties, successful efforts method			4,936,402				4,443,577
Accumulated depletion and depreciation			(974,948	)			(939,769	)
			3,961,454				3,503,808
Transportation and field assets			111,611				104,802
Accumulated depreciation and amortization			(46,905	)			(43,676	)
			64,706				61,126
Other assets			71,492				74,956
Total assets		$	4,487,695			$	4,016,508
Liabilities
Current liabilities:
Accounts payable		$	234,008			$	212,514
Asset retirement obligations			1,667				1,903
Accrued liabilities			39,569				42,964
Accrued interest			21,115				17,595
Unrealized derivative loss			205,697				30,457
Total current liabilities			502,056				305,433
Bank debt			592,500				303,500
Subordinated notes			847,257				847,158
Deferred tax, net			586,932				590,786
Unrealized derivative loss			94,261				45,819
Deferred compensation liability			143,947				120,223
Asset retirement obligations and other liabilities			76,744				75,567
Commitments and contingencies
Stockholders’ equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $.01 par, 250,000,000 shares authorized, 150,123,469 issued at March 31, 2008 and 149,667,497 issued at December 31, 2007			1,501				1,497
Common stock held in treasury - 155,500 shares at March 31, 2008 and December 31, 2007			(5,334	)			(5,334	)
Additional paid-in capital			1,392,101				1,386,884
Retained earnings			366,263				371,800
Accumulated other comprehensive income (loss)			(110,533	)			(26,825	)
Total stockholders’ equity			1,643,998				1,728,022
Total liabilities and stockholders’ equity		$	4,487,695			$	4,016,508

See accompanying notes.

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

		Three Months Ended
		March 31,
		2008				2007
Revenues
Oil and gas sales		$	307,384			$	193,316
Transportation and gathering			1,129				184
Derivative fair value loss			(123,767	)			(42,620	)
Other			20,592				1,961
Total revenue			205,338				152,841
Costs and expenses
Direct operating			32,950				25,414
Production and ad valorem taxes			13,840				10,412
Exploration			16,593				11,710
General and administrative			17,412				14,678
Deferred compensation plan			20,611				11,247
Interest expense			23,146				18,848
Depletion, depreciation and amortization			71,570				47,332
Total costs and expenses			196,122				139,641
Income from continuing operations before income taxes			9,216				13,200
Income tax provision
Current			886				384
Deferred			6,590				4,447
			7,476				4,831
Income from continuing operations			1,740				8,369
Discontinued operations, net of taxes			—				64,768
Net income		$	1,740			$	73,137
Earnings per common share:
Basic — income from continuing operations		$	0.01			$	0.06
— discontinued operations			—				0.47
— net income		$	0.01			$	0.53
Diluted — income from continuing operations		$	0.01			$	0.06
— discontinued operations			—				0.45
— net income		$	0.01			$	0.51
Dividends per common share		$	0.04			$	0.03

See accompanying notes.

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

		Three Months Ended
		March 31,
		2008				2007
Operating activities:
Net income		$	1,740			$	73,137
Adjustments to reconcile to net cash provided from operating activities:
Income from discontinued operations			—				(64,768	)
Loss (income) from equity method investments			275				(411	)
Deferred income tax expense			6,590				4,447
Depletion, depreciation and amortization			71,570				47,332
Unrealized derivative losses			3,249				219
Mark-to-market losses on oil and gas derivatives not designated as hedges			135,221				66,111
Exploration dry hole costs			4,968				4,408
Amortization of deferred financing costs and other			629				526
Deferred and stock-based compensation			27,211				16,437
(Gain) loss on sale of assets and other			(20,468	)			52
Changes in working capital:
Accounts receivable			(31,356	)			(7,393	)
Inventory and other			1,278				(2,260	)
Accounts payable			1,457				(48,911	)
Accrued liabilities and other			3,939				(4,864	)
Net cash provided from continuing operations			206,303				84,062
Net cash provided from discontinued operations			—				7,571
Net cash provided from operating activities			206,303				91,633
Investing activities:
Additions to oil and gas properties			(207,144	)			(182,796	)
Additions to field service assets			(6,813	)			(7,311	)
Acquisitions, net of cash acquired			(333,358	)			(49,114	)
Investing activities of discontinued operations			—				(7,373	)
Investment in other assets			—				79
Proceeds from disposal of assets and other			63,291				234,309
Purchases of marketable securities held by the deferred compensation plan			(2,896	)			—
Proceeds from the sale of marketable securities held by the deferred compensation plan			1,692				—
Net cash used in investing activities			(485,228	)			(12,206	)
Financing activities:
Borrowings on credit facility			423,000				141,500
Repayments on credit facility			(134,000	)			(56,000	)
Debt issuance costs			(2	)			(171	)
Dividends paid			(6,003	)			(4,183	)
Issuance of common stock			2,791				4,900
Purchases of common stock held by the deferred compensation plan			(36	)			—
Proceeds from the sale of common stock held by the deferred compensation plan			949				—
Other financing activities			(11,702	)			—
Net cash provided from financing activities			274,997				86,046
Net increase (decrease) in cash and equivalents			(3,928	)			165,473
Cash and equivalents at beginning of period			4,018				2,382
Cash and equivalents at end of period		$	90			$	167,855

See accompanying notes.

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

		Three Months Ended
		March 31,
		2008				2007
Net income		$	1,740			$	73,137
Net deferred hedging gains (losses), net of tax:
Contract settlements reclassified to income			(3,650	)			(7,435	)
Change in unrealized deferred hedging losses			(81,332	)			(31,528	)
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes			—				337
Comprehensive income (loss)		$	(83,242	)		$	34,511

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, 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 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 may require some entities to change their measurement practices. 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 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. 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 as of 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 $48.5 million at March 31, 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” and all subsequent changes to fair value will be included in our statement of operations. For these securities, interest and dividends and the mark-to-market are included in the income statement category called deferred compensation plan expense. For first quarter 2008, interest and dividends were $187,000 and the mark-to-market was a loss of $4.6 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. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.

     In January 2008, we purchased producing and non-producing Barnett Shale properties in the Fort Worth Basin for $281.6 million. After recording asset retirement obligations of $145,000 and transaction costs of $309,000 the purchase price allocated to proved properties was $211.0 million and unproved properties was $70.6 million. The purchase price allocation is preliminary and subject to adjustment pending normal post closing adjustments.

Dispositions

     In January 2008, we sold shallow oil properties located in East Texas for proceeds of $64.4 million and recorded a gain of $20.7 million in first quarter 2008. In February 2007, we sold our Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. In March 2007, we sold our 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 the Stroud acquisition, we purchased Austin Chalk properties in Central Texas, which we sold in February 2007 for proceeds of $80.4 million. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. Discontinued operations for the three months ended March 31, 2007 are summarized as follows ($ in thousands):

		Three
		Months Ended
		March 31,
		2007
Revenues:
Oil and gas sales		$	16,283
Transportation and gathering			68
Other			310
Gain on disposition of assets and other			93,461
			110,122
Costs and expenses:
Direct operating			2,757
Production and ad valorem taxes			141
Exploration and other			66
Interest expense			845
Depletion, depreciation and amortization			6,672
			10,481
Income from discontinued operations before income taxes			99,641
Income tax expense			34,873
Income from discontinued operations, net of taxes		$	64,768
Production:
Crude oil (bbls)			40,634
Natural gas (mcf)			1,990,276
Total (mcfe)			2,234,084

(6) INCOME TAXES

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

		Three Months Ended
		March 31,
		2008				2007
Income tax expense		$	7,476			$	4,831
Effective tax rate			81.1	%			36.6	%

     We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or 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 March 31, 2008, our overall effective tax rate for continuing operations was different than the statutory rate of 35% primarily due to state income taxes, a decrease in our deferred tax asset related to state tax credit carryforwards ($1.5 million) and a valuation allowance against a deferred tax asset related to our deferred compensation plan ($2.3 million). For the three months ended March 31, 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

     The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):

		Three Months Ended
		March 31,
		2008				2007
Numerator:
Income from continuing operations		$	1,740			$	8,369
Income from discontinued operations, net of taxes			—				64,768
Net income		$	1,740			$	73,137
Denominator:
Weighted average shares outstanding			149,927				139,213
Stock held in the deferred compensation plan and treasury shares			(2,185	)			(1,111	)
Weighted average shares, basic			147,742				138,102
Effect of dilutive securities:
Weighted average shares outstanding			149,927				139,213
Employee stock options, SARs and stock held in the deferred compensation plan			3,935				4,017
Treasury shares			(72	)			—
Dilutive potential common shares for diluted earnings per share			153,790				143,230
Earnings per common share basic and diluted:
Basic — income from continuing operations		$	0.01			$	0.06
— discontinued operations			—				0.47
— net income			0.01				0.53
Diluted — income from continuing operations		$	0.01			$	0.06
— discontinued operations			—				0.45
— net income			0.01				0.51

     Stock appreciation rights for 500 shares were outstanding but not included in the computations of diluted net income per share for the three months ended March 31, 2008 because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations. Stock appreciation rights for 525,975 shares were outstanding but not included in the computations of diluted net income per share for the three months ended March 31, 2007 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 three months ended March 31, 2008 and the year ended December 31, 2007 (in thousands):

		March 31,				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			6,677				14,428
Reclassifications to wells, facilities and equipment based on determination of proved reserves			—				—
Capitalized exploratory well costs charged to expense			(3,598	)			(8,034	)
Divested wells			—				(1,325	)
Balance at end of period			18,132				15,053
Less exploratory well costs that have been capitalized for a period of one year or less			(14,849	)			(12,067	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$	3,283			$	2,986
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			2				2

     The $18.1 million of capitalized exploratory well costs at March 31, 2008 was incurred in 2008 ($5.0 million), in 2007 ($10.1 million) and in 2006 ($3.0 million).

(9) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at March 31, 2008 is shown parenthetically). No interest expense was capitalized during the three months ended March 31, 2008 and 2007.

		March 31,				December 31,
		2008				2007
Bank debt (4.3%)		$	592,500			$	303,500
Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount			197,691				197,602
6.375% Senior Subordinated Notes due 2015			150,000				150,000
7.5% Senior Subordinated Notes due 2016, net of discount			249,566				249,556
7.5% Senior Subordinated Notes due 2017			250,000				250,000
Total debt		$	1,439,757			$	1,150,658

Bank Debt

     In October 2006, we entered into an amended and restated $900.0 million 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 $900.0 million facility amount or the borrowing base. On March 31, 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. Subject to certain conditions, the facility amount may be increased to the borrowing base amount with twenty days notice. At March 31, 2008, the outstanding balance under the bank credit facility was $592.5 million and there was $307.5 million of

borrowing capacity available. As of April 1, 2008, the facility amount was increased to $1.0 billion. 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 5.0% for the three months ended March 31, 2008 compared to 6.5% for the three months ended March 31, 2007. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At March 31, 2008, the commitment fee was 0.25% and the interest rate margin was 1.0%. At April 21, 2008, the interest rate (including applicable margin) was 4.9%.

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 or 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 greater than to 1 to 1. We were in compliance with our covenants under the bank credit facility at March 31, 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 March 31, 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 and abandonment costs for the three months ended March 31, 2008 is as follows (in thousands):

		Three
		Months Ended
		March 31,
		2008
Beginning of period		$	75,308
Liabilities incurred			908
Liabilities settled			(493	)
Disposition of wells			(898	)
Accretion expense			1,217
Change in estimate			50
End of period		$	76,092

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

(11) CAPITAL STOCK

     We have authorized capital stock of 260 million shares, which includes 250 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:

		Three				Year
		Months Ended				Ended
		March 31,				December 31,
		2008				2007
Beginning balance			149,667,497				138,931,565
Public offering			—				8,050,000
Stock options/SARs exercised			427,696				2,220,627
Restricted stock grants			19,867				408,067
In lieu of bonuses			8,409				29,483
Contributed to 401(k) plan			—				27,755
			455,972				10,735,932
Ending balance			150,123,469				149,667,497

Treasury Stock

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. As of March 31, 2008, we have $4.7 million of approved repurchases remaining.

(12) DERIVATIVE ACTIVITIES

     At March 31, 2008, we had open swap contracts covering 68.2 Bcf of gas at prices averaging $8.47 per mcf. We also had collars covering 74.0 Bcf of gas at weighted average floor and cap prices which range from $8.10 to $9.53 per mcf and 5.4 million barrels of oil at weighted average floor and cap prices that range from $61.87 to $75.76 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 March 31, 2008, was a net unrealized pre-tax loss of $300.1 million. These contracts expire monthly through December 2009.

     The following table sets forth our derivative volumes by year as of March 31, 2008:

Period		Contract Type		Volume Hedged		Average Hedge Price
Natural Gas
2008		Swaps		155,000 Mmbtu/day			$8.52
2008		Collars		70,000 Mmbtu/day			$7.59 — $10.30
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. 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 March 31, 2008, an unrealized pre-tax derivative loss of $178.1 million was recorded in the balance sheet caption accumulated other comprehensive income (loss). This loss is expected to be reclassified into earnings in 2008 ($86.7 million) and 2009 ($91.4 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 $5.2 million of gains in the first three months of 2008 compared to gains of $11.8 million in the same period of 2007. Any ineffectiveness associated with these hedges is reflected in the income statement caption derivative fair value loss. The three months ended March 31, 2008 includes ineffective unrealized losses of $3.2 million compared to losses of $219,000 in the same period of 2007.

     A portion of our derivatives do not qualify for hedge accounting but are, to a degree, economic hedges of 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 loss (see table below). In fourth quarter 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices and are marked to market. Also, as a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of our derivatives which were 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 were sold in first quarter 2008.

     During third and fourth quarter 2007, in addition to the swaps and collars above, we 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 our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $2.4 million at March 31, 2008.

Derivative Fair Value Loss

     The following table presents information about the components of derivative fair value loss in the three months ended March 31, 2008 and 2007 (in thousands):

		Three Months Ended
		March 31,
		2008				2007
Hedge ineffectiveness — realized		$	705			$	—
— unrealized			(3,249	)			(219	)
Change in fair value of derivatives that do not qualify for hedge accounting			(135,221	)			(66,111	)
Realized gain on settlements — gas (a)			16,584				23,710
Realized loss on settlements — oil (a)			(2,586	)			—
Derivative fair value loss		$	(123,767	)		$	(42,620	)

     The combined fair value of derivatives included in our consolidated balance sheets as of March 31, 2008 and December 31, 2007 is summarized below (in thousands). Derivative activities are conducted with major financial and commodities trading institutions which we believe are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. We have master netting agreements with our counterparties and the credit worthiness of our counterparties is subject to periodic review.

		March 31,				December 31,
		2008				2007
Derivative assets:
Natural gas — swaps		$	—			$	54,577
— collars			—				4,916
— basis swaps			2,244				1,082
Crude oil — collars			—				(6,475	)
		$	2,244			$	54,100
Derivative liabilities:
Natural gas — swaps		$	(109,075	)		$	6,594
— collars			(67,868	)			11,302
— basis swaps			188				(937	)
Crude oil — collars			(123,203	)			(93,235	)
		$	(299,958	)		$	(76,276	)

Adoption of SFAS No. 157

     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 (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. 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 measurement). 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 Level 1, which are either 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 March 31, 2008, we have no significant Level 3 measurements.

     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 March 31, 2008 Using
						Quoted Prices in				Significant Other				Significant
		Total Carrying				Active Markets for				Observable				Unobservable
		Value as of				Identical Assets				Inputs				Inputs
		March 31, 2008				(Level 1)				(Level 2)				(Level 3)
Trading securities held in the deferred compensation plans		$	48,499			$	48,499			$	—			$	—
Derivatives — swaps			(109,075	)			—				(109,075	)			—
— collars			(191,071	)			—				(191,071	)			—
— basis swaps			2,432				—				2,432				—

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

     We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified options, stock appreciation rights (“SARs”), restricted stock awards, phantom stock rights 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			763,515				58.61
Exercised			(548,691	)			12.25
Expired/forfeited			(13,363	)			29.89
Outstanding on March 31, 2008			7,973,786			$	22.21

     The following table shows information with respect to outstanding stock options and SARs at March 31, 2008:

		Outstanding												Exercisable
						Weighted-Average				Weighted-Average								Weighted-Average
						Remaining				Exercise								Exercise
Range of Exercise Prices		Shares				Contractual Life				Price				Shares				Price
$1.29—$9.99			2,108,569				2.26			$	4.85				2,108,569			$	4.85
10.00 — 19.99			2,122,824				2.15				16.32				2,122,824				16.32
20.00 — 29.99			1,429,130				2.99				24.42				743,044				24.38
30.00 — 39.99			1,533,338				3.99				33.87				307,105				32.38
40.00 — 49.99			17,900				4.55				42.56				—				—
50.00 — 59.99			757,525				4.87				58.58				—				—
60.00 — 64.31			4,500				4.99				64.34				—				—
Total			7,973,786				2.95			$	22.21				5,281,542			$	13.81

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2008 was $18.35. 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 assumptions: risk-free interest rate of 2.27%; dividend yield of 0.27%; expected volatility of 40%; and an expected life of 3.49 years.

     As of March 31, 2008, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $328.8 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $262.2 million and 2.41 years. As of March 31, 2008, the number of fully-vested awards and awards expected to vest was 7.8 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $21.74 and 2.92 years and the aggregate intrinsic value was $324.8 million. As of March 31, 2008, unrecognized compensation cost related to the awards was $26.8 million, which is expected to be recognized over a weighted average period of 1.4 years.

Restricted Stock Grants

     During first quarter 2008, 176,400 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $58.60 and have a three-year vesting period. In first quarter 2007, we issued 10,000 shares of restricted stock as compensation to employees at an average price of $31.00 and a three year vesting period. We recorded compensation expense related to restricted stock grants which is based upon the market value of the shares on the date of grant of $3.3 million in the first three months of 2008 compared to $1.2 million in the three-month period ended March 31, 2007. As of March 31, 2008, unrecognized compensation cost related to these restricted stock awards was $24.1 million, which is expected to be recognized over the next 3 years. All of our restricted stock grants are held in our deferred

compensation plans (see discussion below). The vesting of these shares is dependent only upon the employees’ continued service with us.

     A summary of the status of our non-vested restricted stock outstanding at March 31, 2008 is presented below:

						Weighted
						Average Grant
		Shares				Date Fair Value
Non-vested shares outstanding at December 31, 2007			563,660			$	30.42
Granted			176,454				58.60
Vested			(92,307	)			35.99
Forfeited			(1,087	)			24.32
Non-vested shares outstanding at March 31, 2008			646,720			$	37.32

Deferred Compensation Plan

     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 invests such amounts in Range common stock or makes 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 is 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 expense related to our deferred compensation plan of $20.6 million in the first three months of 2008 compared to $11.2 million in the first three months of 2007.

(14) SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended
		March 31,
		2008				2007
		(in thousands)
Non-cash investing and financing activities included:
Asset retirement costs capitalized		$	814			$	1,123
Net cash provided from operating activities included:
Income taxes paid		$	—			$	10
Interest paid			18,975				20,324

     The consolidated statement of cash flows for the three months ended March 31, 2008 excludes the following non-cash transactions: grants of 176,400 restricted shares, vesting of 121,500 restricted shares and forfeitures of 1,100 restricted shares.

(15) COMMITMENTS AND CONTINGENCIES

Litigation

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

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

		March 31,				December 31,
		2008				2007
		(in thousands)
Oil and gas properties:
Properties subject to depletion		$	4,550,262			$	4,172,151
Unproved properties			386,140				271,426
Total			4,936,402				4,443,577
Accumulated depreciation, depletion and amortization			(974,948	)			(939,769	)
Net capitalized costs		$	3,961,454			$	3,503,808

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

		Three Months
		Ended				Year Ended
		March 31,				December
		2008				31, 2007
		(in thousands)
Acquisitions:
Unproved leasehold		$	100,182			$	4,552
Proved oil and gas properties			211,013				253,064
Asset retirement obligations			145				3,301
Acreage purchases			22,163				78,095
Development			214,838				734,987
Exploration:
Drilling			18,549				40,567
Expense			15,504				39,872
Stock-based compensation expense			1,089				3,473
Gas gathering facilities			7,736				18,655
Subtotal			591,219				1,176,566
Asset retirement obligations			814				(7,075	)
Total costs incurred		$	592,033			$	1,169,491

(18) ACCOUNTING STANDARDS NOT YET ADOPTED

     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. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are in the process of evaluating the impact of SFAS No. 161 on our consolidated financial statements.

     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 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 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 34% for first quarter 2008 over the same period of 2007. This increase includes a 59% increase in oil and gas sales partially offset by a 190% increase in derivative fair value loss. For first quarter 2008, total revenues includes a $20.7 million gain on the sale of certain East Texas properties. Oil and gas sales vary due to changes in volumes of production sold and commodity prices. For first quarter 2008, production increased 28% due to the continued success of our drilling program and our acquisitions. Realized prices were higher by 16% in first quarter 2008. 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 production in North American and worldwide.

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 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 loss. The following table summarized the primary components of oil and gas sales for the three months ended March 31, 2008 and 2007 (in thousands):

		Three Months Ended March 31,
		2008				2007				Change				%
Oil and Gas Sales:
Oil wellhead		$	71,419			$	46,961			$	24,458				52	%
Oil hedges realized			(15,392	)			(12	)			(15,380	)			128,167	%
Total oil revenue			56,027				46,949				9,078				19	%
Gas wellhead			214,516				126,324				88,192				70	%
Gas hedges realized			20,574				11,814				8,760				74	%
Total gas revenue			235,090				138,138				96,952				70	%
NGL			16,267				8,229				8,038				98	%
Combined wellhead			302,202				181,514				120,688				66	%
Combined hedges			5,182				11,802				(6,620	)			56	%
Total oil and gas sales		$	307,384			$	193,316			$	114,068				59	%

     Our production continues to grow through continued drilling success and additions from acquisitions. For first quarter 2008, our production volumes increased 27% in our Appalachian Area, 28% in our Southwestern Area and 58% in our Gulf Coast Area.

		Three Months Ended
		March 31,
		2008				2007
Production:
Crude oil (bbls)			754,545				838,488
NGLs (bbls)			312,500				273,130
Natural gas (mcf)			27,322,774				19,694,023
Total (mcfe) (a)			33,725,044				26,363,731
Average daily production:
Crude oil (bbls)			8,292				9,317
NGLs (bbls)			3,434				3,035
Natural gas (mcf)			300,250				218,822
Total (mcfe) (a)			370,605				292,930

     Our average realized price (including all derivative settlements) received for oil and gas was $9.55 per mcfe in first quarter 2008 compared to $8.23 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlement for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months ended March 31, 2008 and 2007 is shown below:

		Three Months Ended
		March 31,
		2008				2007
Average sales prices (wellhead):
Crude oil (per bbl)		$	94.65			$	56.01
NGLs (per bbl)			52.06				30.13
Natural gas (per mcf)			7.85				6.41
Total (per mcfe) (a)			8.96				6.88
Average realized price (including derivatives that qualify for hedge accounting):
Crude oil (per bbl)			74.25				55.99
NGLs (per bbl)			52.06				30.13
Natural gas (per mcf)			8.60				7.01
Total (per mcfe) (a)			9.11				7.33
Average realized price (including all derivative settlements):
Crude oil (per bbl)			70.25				55.99
NGLs (per bbl)			52.06				30.13
Natural gas (per mcf)			9.25				8.22
Total (per mcfe) (a)			9.55				8.23
Average NYMEX prices (b)
Oil (per bbl)			97.90				58.27
Natural gas (per mcf)			8.07				6.96

     Derivative fair value loss includes a loss of $123.8 million in 2008 compared to a loss of $42.6 million in the same period of 2007. Some of our derivatives do not qualify for hedge accounting but are, to a degree, economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. All unrealized and realized gains and losses related to these contracts are included in the caption derivative fair value income loss. In fourth quarter 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices. Also, as a result of the sale of our Gulf of Mexico properties in first quarter 2007, the portion of our derivatives that were designated to our Gulf of Mexico production is being marked to market. In third quarter 2007, we entered into basis swap agreements, which do not qualify for hedge accounting and are 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 occurred in first quarter 2008. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from non-hedge derivatives are included in total revenues and are not included in our balance sheet caption accumulated other comprehensive income. Due to continued rising commodity prices for oil and natural gas in 2008, we reported a non-cash unrealized mark-to-market loss from our oil and gas derivatives of $135.2 million for the quarter ended March 31, 2008. If commodity prices for oil and natural gas continue to rise, we would expect to incur additional realized and non-cash unrealized losses from our oil and gas hedges. If this occurs, our results of operations, net income and earnings per share may be adversely affected. Hedge ineffectiveness included in this income statement category is associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133.

     The following table presents information about the components of derivative fair value loss for the three months ended March 31, 2008 and 2007 (in thousands):

		Three Months Ended
		March 31,
		2008				2007
Hedge ineffectiveness — realized (b) (c)		$	705			$	—
— unrealized (a)			(3,249	)			(219	)
Change in fair value of derivatives that do not qualify for hedge accounting (a)			(135,221	)			(66,111	)
Realized gain on settlements — gas (b) (c)			16,584				23,710
Realized loss on settlements — oil (b) (c)			(2,586	)			—
Derivative fair value loss		$	(123,767	)		$	(42,620	)

     Other revenue increased in 2008 to $20.6 million from $2.0 million in 2007. The 2008 period includes a gain of $20.7 million from the sale of certain East Texas properties. Other revenue for 2007 includes insurance proceeds of $1.0 million and income from equity method investments of $411,000.

Comparison of First Quarter 2008 versus 2007 — Expenses

     Our costs have increased as we continue to grow. We believe some of our expense fluctuations should be analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on an mcfe basis for the three months ended March 31, 2008 and 2007:

		Three Months Ended
		March 31,
Operating expenses per mcfe		2008				2007				Change				%
Direct operating expense		$	0.98			$	0.96			$	0.02				2	%
Production and ad valorem tax expense			0.41				0.39				0.02				5	%
General and administrative expense			0.52				0.56				(0.04	)			7	%
Interest expense			0.69				0.71				(0.02	)			3	%
Depletion, depreciation and amortization expense			2.12				1.80				0.32				18	%

     Direct operating expense increased $7.5 million in first quarter 2008 to $33.0 million due to higher oilfield service costs and higher volumes. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $1.9 million ($0.06 per mcfe) of workover costs in 2008 versus $1.4 million ($0.05 per mcfe) in 2007. On a per mcfe basis, direct operating expenses increased $0.02 from the same period of 2007 with the increase consisting primarily of higher workover costs ($0.01 per mcfe) and higher well service costs ($0.01 per mcfe). The following table summarizes direct operating expenses per mcfe for first quarter 2008 and 2007:

		Three Months Ended
		March 31,
														%
		2008				2007				Change				Change
Lease operating expense		$	0.90			$	0.89			$	0.01				1	%
Workovers			0.06				0.05				0.01				20	%
Stock-based compensation			0.02				0.02				—				—
Total direct operating expenses		$	0.98			$	0.96			$	0.02				2	%

     Production and ad valorem taxes are paid based on market prices and not hedged prices. These taxes increased $3.4 million or 33% from the same period of the prior year due to higher volumes and higher prices. On a per mcfe basis, production and ad valorem taxes increased to $0.41 in 2008 from $0.39 in the same period of 2007.

     General and administrative expense for the first quarter of 2008 increased $2.7 million from 2007 due to higher salaries and benefits ($1.6 million), and higher stock-based compensation ($976,000). The stock-based compensation represents amortization of restricted stock grants and stock option/SARs expense under SFAS No. 123(R). On a per mcfe basis, general and administrative expense decreased from $0.56 in first quarter 2007 to $0.52 in first quarter 2008. The following table summarizes general and administrative expenses per mcfe for first quarter 2008 and 2007:

		Three Months Ended
		March 31,
														%
		2008				2007				Change				Change
General and administrative		$	0.38			$	0.42			$	(0.04	)			10	%
Stock-based compensation			0.14				0.14				—				—
Total general and administrative expenses		$	0.52			$	0.56			$	(0.04	)			7	%

     Interest expense for first quarter 2008 increased $4.3 million to $23.1 million due to the refinancing of certain debt from floating to higher fixed rates in third quarter 2007 and higher debt balances. In September 2007, we issued $250.0 million of 7.5% Notes due 2017 which added $4.7 million of interest costs in first quarter 2008. The proceeds from the issuance of the 7.5% Notes due 2017 were used to retire lower interest bank debt, to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for first quarter 2008 was $539.8 million compared to $507.4 million for first quarter 2007 and the weighted average interest rates were 5.0% in first quarter 2008 compared to 6.5% in the same quarter of 2007.

     Depletion, depreciation and amortization (“DD&A”) increased $24.2 million, or 51%, to $71.6 million in the first quarter 2008 with a 28% increase in production and a 17% increase in depletion rates. The increase in DD&A per mcfe is related to increasing drilling costs, higher acquisition costs and the mix of our production. First quarter 2008 also included higher acreage expiration expense of $1.3 million ($0.04 per mcfe). On a per mcfe basis, DD&A increased from $1.80 in first quarter 2007 to $2.12 in first quarter 2008.

     Our operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense and deferred compensation plan expenses. In the three months ended March 31, 2007 and 2008, stock-based compensation represents the amortization of restricted stock grants and expenses related to the adoption of SFAS No. 123(R). In 2008, stock-based compensation is a component of direct operating expense ($578,000), exploration expense ($1.1 million) and general and administrative expense ($4.6 million) for a total of $6.4 million. In 2007, stock-based compensation is a component of direct operating expense ($397,000), exploration expense ($739,000) and general and administrative expense ($3.6 million) for a total of $4.9 million.

     Exploration expense increased $4.9 million due to higher seismic spending and increased personnel and dry hole costs. The following table details our exploration-related expenses for the three months ended March 31, 2008 and 2007 (in thousands):

		Three Months Ended
		March 31,
		2008				2007				Change				%
Dry hole expense		$	4,968			$	4,408			$	560				13	%
Seismic			6,744				3,476				3,268				94	%
Personnel expense			2,638				1,997				641				32	%
Stock-based compensation expense			1,089				739				350				47	%
Delay rentals and other			1,154				1,090				64				6	%
Total exploration expense		$	16,593			$	11,710			$	4,883				42	%

     Deferred compensation plan expense for first quarter 2008 increased $9.4 million from 2007 primarily due to an increase in our stock price. Our stock price increased from $51.36 at December 31, 2007 to $63.45 at March 31, 2008. This non-cash expense relates to the increase or decrease in value of our vested common stock and other investments held in our deferred compensation plans.

     Income tax expense for 2008 increased to $7.5 million, which included a $4.0 million charge for certain discrete tax items somewhat offset by a 30% decrease in income from continuing operations before taxes compared to the same period of 2007. The discrete tax items included in first quarter 2008 include a $2.3 million valuation allowance recorded against our deferred tax asset related to our deferred compensation plan and a $1.5 million charge related to a decrease in our deferred tax asset on state tax credit carryforwards. First quarter 2008 provided for a tax expense at an effective rate of 81% compared to 37% in the same period of 2007. Current income taxes of $886,000 included state income taxes of $636,000 and $250,000 of federal income taxes. We expect our effective tax rate to be approximately 38% for the remainder of 2008.

     Discontinued operations in first quarter 2007 include the operating results related to our Gulf of Mexico properties and Austin Chalk properties sold in first quarter 2007.

Liquidity and Capital Resources

     Our main sources of liquidity and capital resources are internally generated cash flow from operations, a committed bank credit facility, asset sales and access to both the debt and equity capital markets. During the three months ended March 31, 2008, our cash provided from continuing operations was $206.3 million and we spent $547.3 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $275.0 million. At March 31, 2008, we had $90,000 in cash, total assets of $4.5 billion and a debt-to-capitalization ratio of 46.7%. Long-term debt at March 31, 2008 totaled $1.4 billion including $592.5 million of bank credit facility debt and $847.3 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at March 31, 2008 was $307.5 million.

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

Credit Arrangements

     Effective April 1, 2008, our bank credit facility amount was increased from $900.0 million to $1.0 billion. On April 1, 2008, the bank credit facility had a $1.5 billion borrowing base and a $1.0 billion facility amount. Credit availability is equal to the lesser of the facility amount or the borrowing base resulting in credit availability of $359.5 million on April 21, 2008.

     Our bank credit facility and our indentures governing our senior subordinated notes all contain covenants that, among other things, limit our ability to pay dividends and incur additional indebtedness. We were in compliance with these covenants at March 31, 2008. Please see Note 9 to our consolidated financial statements for additional information.

Cash Flow

     Cash flow from operations primarily are affected by production and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We sell substantially all of our oil and gas production under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. Any payments due counterparties under our derivative contracts should ultimately be funded by higher prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowing under the credit facility. As of March 31, 2008, we have entered into hedging agreements covering 76.7 Bcfe for 2008 and 97.8 Bcfe for 2009.

     Net cash provided from continuing operations for the three months ended March 31, 2008 was $206.3 million compared to $84.1 million in the three months ended March 31, 2007. Cash flow from operations was higher than the prior year due to higher production from development activity and acquisitions. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in the consolidated statement of cash flows) in the three months ended March 31, 2008 was a negative $24.7 million compared to a negative $63.4 million in the same period of the prior year.

     Net cash used in investing for the three months ended March 31, 2008 was $485.2 million compared to $12.2 million in the same period of 2007. The 2008 period included $207.1 million of additions to oil and gas properties and $333.4 million of acquisitions, offset by proceeds of $63.3 million from asset sales. Acquisitions for first quarter 2008 include the purchase of producing and non-producing Barnett Shale properties for $281.6 million. The 2007 period included $182.8 million of additions to oil and gas properties and $49.1 million of acquisitions, offset by proceeds of $234.3 million from asset sales.

     Net cash provided from financing for the three months ended March 31, 2008 was $275.0 million compared to $86.0 million in the first three months of 2007. This increase was primarily the result of higher borrowings under our credit facility. During the first three months of 2008, total debt increased $289.0 million.

Dividends

     On March 31, 2008, the Board of Directors declared a dividend of four cents per share ($6.0 million) on our common stock, which was paid on March 31, 2008 to stockholders of record at the close of business on March 15, 2008.

Capital Requirements and Contractual Cash Obligations

     The 2008 capital budget is currently set at $1.1 billion (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow and asset sales. For the three months ended March 31, 2008, $250.0 million of development and exploration spending was funded with internal cash flow and borrowings under our credit facility.

     There have been no significant changes to our contractual obligations or off-balance sheet arrangements subsequent to December 31, 2007.

Other Contingencies

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

Hedging — Oil and Gas Prices

     We enter into hedging agreements to reduce the impact of oil and gas price volatility. At March 31, 2008, swaps were in place covering 68.2 Bcf of gas at prices averaging $8.47 per mcf. We also have collars covering 74.0 Bcf of gas at weighted average floor and cap prices which range from $8.10 to $9.53 per mcf and 5.4 million barrels of oil at weighted average floor and cap prices that range from $61.87 to $75.76 per barrel. Their fair value at March 31, 2008 (the estimated amount that would be realized on termination based on contract price and a reference price, generally NYMEX) was a net unrealized pre-tax loss of $300.1 million. The contracts expire monthly through December 2009. Settled transaction gains and losses for derivatives that qualify for hedge accounting are determined monthly and are included as increases or decreases in oil and gas sales in the period the hedged production is sold. In first quarter 2008, oil and gas sales included realized hedging gains of $5.2 million compared to gains of $11.8 million in the same quarter of 2007.

     At March 31, 2008, the following commodity derivative contracts were outstanding:

										Average
Period		Contract Type				Volume Hedged				Hedge Price
Natural Gas
2008		Swaps				155,000 Mmbtu/day				$	8.52
2008		Collars				70,000 Mmbtu/day				$	7.59—$10.30
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

     Some of our derivatives do not qualify for hedge accounting but are, to a degree, economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value on our balance sheet under the captions unrealized derivative gains and losses. We recognize all unrealized and realized gains and losses related to these contracts in our income statement caption called derivative fair value loss.

     As of fourth quarter 2005, certain of our gas derivatives no longer qualified for hedge accounting and are marked to market. Also, as a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of derivatives which were designated to our Gulf Coast production are marked to market. In fourth quarter of 2007, we began marking a portion of our oil hedges designated as Permian production to market due to the anticipated sale of a portion of our Permian properties that occurred in first quarter 2008. Derivatives that no longer qualify for hedge accounting are accounted for using the mark-to-market accounting method described above. As of March 31, 2008, hedges on 66.3 Bcfe no longer qualify or are not designated for hedge accounting.

     During third and fourth quarter 2007, in addition to the swaps and collars above, we entered into basis swap agreements that do not qualify as hedges for hedge accounting purposes and are marked to market. The price we receive for our production can be less than NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $2.4 million at March 31, 2008.

Interest Rates

     At March 31, 2008, we had $1.4 billion of debt outstanding. Of this amount, $847.3 million bore interest at fixed rates averaging 7.3%. Bank debt totaling $592.5 million bears interest at floating rates, which averaged 4.3% at March 31, 2008. The 30 day LIBOR rate on March 31, 2008 was 2.7%.

Inflation and Changes in Prices

     Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. During first quarter 2008, we received an average of $94.65 per barrel of oil and $7.85 per mcf of gas before derivative contracts compared to $56.01 per barrel of oil and $6.41 per mcf of gas in the same period of the prior year. Although certain of our costs are affected by

general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through 2007, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on capital costs. We expect these costs to remain high in 2008.

Accounting Standards Not Yet Adopted

     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). 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. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are in the process of evaluating the impact of SFAS No. 161 on our Consolidated Financial Statements.

     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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market Risk

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

Commodity Price Risk

     We periodically enter into derivative arrangements with respect to our oil and gas production. These arrangements are intended to reduce the impact of oil and gas price fluctuations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars which assume a minimum floor price and a predetermined ceiling price. Historically, we applied hedge accounting to derivatives utilized to manage price risk associated with our oil and gas production. Accordingly, we recorded change in the fair value of our swap and collar contracts, including changes associated with time value, under the balance sheet caption accumulated other comprehensive income (loss) and into oil and gas sales when the forecasted sale of production occurred. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge is reported currently each period under the income statement caption derivative fair value loss. Some of our derivatives do not qualify for hedge accounting but are, to a degree, economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value on our consolidated balance sheet under the captions unrealized derivative gains and losses. We recognize all unrealized and realized gains and losses related to these contracts in our income statement under the caption derivative fair value loss. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction.

     As of March 31, 2008, we had oil and gas swaps in place covering 68.2 Bcf of gas. We also had collars covering 74.0 Bcf of gas and 5.4 million barrels of oil. These contracts expire monthly through December 2009. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of March 31, 2008, approximated a net unrealized pre-tax loss of $300.1 million.

     At March 31, 2008, the following commodity derivative contracts were outstanding:

Period		Contract Type				Volume Hedged				Average Hedge Price				Fair Market Value
														(in thousands)
Natural Gas
2008		Swaps				155,000 Mmbtu/day				$	8.52			$	(75,270	)
2008		Collars				70,000 Mmbtu/day				$	7.59—$10.30			$	(17,214	)
2009		Swaps				70,000 Mmbtu/day				$	8.38			$	(33,805	)
2009		Collars				150,000 Mmbtu/day				$	8.28—$9.27			$	(50,655	)
Crude Oil
2008		Collars				9,000 bbl/day				$	59.34—$75.48			$	(60,703	)
2009		Collars				8,000 bbl/day				$	64.01—$76.00			$	(62,500	)

Other Commodity Risk

     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. In addition to the collars and swaps detailed above, during third and fourth quarter 2007, we entered into basis swap agreements which do not qualify for hedge accounting purposes and are marked to market. The price we receive for our gas production can be 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 the basis adjustments. The fair value of the basis swaps was a net realized pre-tax gain of $2.4 million at March 31, 2008.

     In the first three months of 2008, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $30.1 million. If oil and gas future prices at March 31, 2008 declined 10%, the unrealized hedging loss at that date would have decreased by $151.9 million.

     Interest rate risk. At March 31, 2008, we had $1.4 billion of debt outstanding. Of this amount, $847.3 million bore interest at fixed rates averaging 7.3%. Senior debt totaling $592.3 million bore interest at floating rates averaging 4.3%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $5.9 million.

Item 4. CONTROLS AND PROCEDURES

     As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 or the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting us to material information required to be included in this report. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 6. Exhibits

(a) EXHIBITS

Exhibit
Number		Description
3.1		Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004 as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005)
3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form 10-K (File No. 001-12209) as filed with the SEC on March 3, 2004)
10.1*		Fourth Amendment (dated April 1, 2008) to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders
31.1*		Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*		Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*		Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*		Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002