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, 2007

or

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

For the transition period from                      to                     

Commission file number 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
777 Main Street, Suite 800, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

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

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

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ          No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer “in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer þ          Accelerated Filer o          Non-Accelerated Filer o

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

Yes o          No þ

148,015,600 Common Shares were outstanding on April 24, 2007.

 

 

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended March 31, 2007

     Unless the context otherwise indicates, all references in this report to “Range” “we” “us” or “our” are to Range Resources Corporation and its subsidiaries.

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			18
Item 3.		Quantitative and Qualitative Disclosures about Market Risk			24
Item 4.		Controls and Procedures			26
PART II – OTHER INFORMATION
Item 6.		Exhibits			27
First Amendment to the Third Amended and Restated Credit Agreement
Second Amendment to the Third Amended and Restated Credit Agreement
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

PART I – Financial Information

ITEM 1. – Financial Statements

RANGE RESOURCES CORPORATION

		March 31,				December 31,
		2007				2006
		(Unaudited)
Assets
Current assets:
Cash and equivalents		$	167,855			$	2,382
Accounts receivable, less allowance for doubtful accounts of $547 and $746			134,132				130,349
Assets held for sale			—				79,304
Unrealized derivative gain			30,443				93,588
Inventory and other			12,819				14,714
Total current assets			345,249				320,337
Unrealized derivative gain			11,181				61,068
Equity method investment			14,761				13,618
Oil and gas properties, successful efforts method			3,798,156				3,641,227
Accumulated depletion and depreciation			(1,008,306	)			(964,551	)
			2,789,850				2,676,676
Transportation and field assets			86,270				80,066
Accumulated depreciation and amortization			(35,149	)			(32,923	)
			51,121				47,143
Other assets			68,722				68,832
Total assets		$	3,280,884			$	3,187,674
Liabilities
Current liabilities:
Accounts payable		$	122,028			$	172,081
Asset retirement obligation			3,457				4,216
Accrued liabilities			29,874				38,500
Accrued interest			11,754				12,938
Unrealized derivative loss			17,831				4,621
Total current liabilities			184,944				232,356
Bank debt			537,500				452,000
Subordinated notes			596,874				596,782
Deferred tax, net			485,279				468,643
Unrealized derivative loss			2,200				266
Deferred compensation liability			101,463				90,094
Asset retirement obligations			73,710				91,372
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, 139,602,682 issued at March 31, 2007 and 138,931,565 issued at December 31, 2006			1,396				1,389
Additional paid-in capital			1,093,094				1,079,994
Retained earnings			229,267				160,313
Common stock held by employee benefit trust, 1,830,697 and 1,853,279 shares, respectively, at cost			(22,738	)			(22,056	)
Accumulated other comprehensive income (loss)			(2,105	)			36,521
Total stockholders’ equity			1,298,914				1,256,161
Total liabilities and stockholders’ equity		$	3,280,884			$	3,187,674

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended
		March 31,
		2007				2006
Revenues
Oil and gas sales		$	217,026			$	166,555
Transportation and gathering			184				(39	)
Mark-to-market on oil and gas derivatives			(66,111	)			11,281
Other			1,742				1,433
Total revenue			152,841				179,230
Costs and expenses
Direct operating			25,414				18,133
Production and ad valorem taxes			10,412				9,551
Exploration			11,710				8,922
General and administrative			14,678				11,330
Deferred compensation plan			11,247				4,479
Interest expense			18,848				10,234
Depletion, depreciation and amortization			47,332				31,651
Total costs and expenses			139,641				94,300
Income from continuing operations before income taxes			13,200				84,930
Income tax provision
Current			384				578
Deferred			4,447				31,150
			4,831				31,728
Income from continuing operations			8,369				53,202
Discontinued operations, net of taxes			64,768				2,473
Net income		$	73,137			$	55,675
Earnings per common share:
Basic – income from continuing operations		$	0.06			$	0.41
– discontinued operations			0.47				0.02
– net income		$	0.53			$	0.43
Diluted – income from continuing operations		$	0.06			$	0.40
– discontinued operations			0.45				0.01
– net income		$	0.51			$	0.41
Dividends per common share		$	0.03			$	0.02

See accompanying notes.

RANGE RESOURCES CORPORATION

		Three Months Ended
		March 31,
		2007				2006
Operating activities:
Net income		$	73,137			$	55,675
Adjustments to reconcile to net cash provided from operating activities:
Gain from discontinued operations			(64,768	)			(2,473	)
Gain from equity method investment			(411	)			—
Deferred income tax expense			4,447				31,150
Depletion, depreciation and amortization			47,332				31,651
Unrealized derivative (gains)/losses			219				(1,252	)
Mark-to-market (gains)/losses on oil and gas derivatives			66,111				(11,281	)
Exploration dry hole costs			4,408				1,700
Amortization of deferred issuance costs and other			526				406
Non-cash compensation			16,437				8,056
Loss on sale of assets and other			52				418
Changes in working capital:
Accounts receivable			(7,393	)			32,263
Inventory and other			(2,260	)			(1,630	)
Accounts payable			(48,911	)			(15,270	)
Accrued liabilities and other			(4,864	)			(12,986	)
Net cash provided from continuing operations			84,062				116,427
Net cash provided from discontinued operations			7,571				9,082
Net cash provided from operating activities			91,633				125,509
Investing activities:
Additions to oil and gas properties			(182,796	)			(91,099	)
Additions to field service assets			(7,311	)			(3,362	)
Acquisitions, net of cash acquired			(49,114	)			(9,980	)
Investing activities of discontinued operations			(7,373	)			(3,156	)
Investment in other assets			79				—
Proceeds from disposal of assets and other			234,309				149
Net cash used in investing activities			(12,206	)			(107,448	)
Financing activities:
Borrowings on credit facility			141,500				87,600
Repayments on credit facility			(56,000	)			(110,700	)
Debt issuance costs			(171	)			(450	)
Dividends paid			(4,183	)			(2,623	)
Issuance of common stock			4,900				4,711
Net cash provided from (used in) financing activities			86,046				(21,462	)
Net increase (decrease) in cash and equivalents			165,473				(3,401	)
Cash and equivalents at beginning of period			2,382				4,750
Cash and equivalents at end of period		$	167,855			$	1,349

See accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)

		Three Months Ended
		March 31,
		2007				2006
Net income		$	73,137			$	55,675
Net deferred hedge gains (losses), net of tax:
Contract settlements reclassified to income			(23,517	)			11,281
Change in unrealized deferred hedging gains (losses)			(15,446	)			41,234
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes			337				1,121
Comprehensive income (loss)		$	34,511			$	109,311

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 is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange.

(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 2006 Annual Report on Form 10-K. 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. Certain reclassifications have been made to the presentation of prior periods to conform to current year presentation.

     During the first quarter of 2007, we sold our interests in the following oil and gas assets:

Description of Assets		Date Divested
Austin Chalk, Central Texas		February 2007
Gulf of Mexico		March 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 4 for additional information regarding discontinued operations.

(3) ACQUISITIONS AND DISPOSITIONS

     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. We purchased various properties for $49.0 million in the first three months of 2007 compared to $10.0 million during the three months ended March 31, 2006. The purchases included $31.4 million and $335,000 for proved oil and gas reserves for the three months ended March 31, 2007 and 2006, respectively, with the remainder representing acreage purchases.

     In June 2006 we acquired Stroud Energy, Inc. (“Stroud”), a private oil and gas company with operations in the Barnett Shale in North Texas, the Cotton Valley in East Texas and the Austin Chalk in Central Texas. To acquire Stroud, we paid $171.5 million of cash and issued 6.5 million shares of our common stock.

     The following table summarizes the final purchase price allocation of fair values of assets acquired and liabilities assumed at closing (in thousands):

Cash paid (including transaction costs)		$	171,529
6.5 million shares of common stock (at fair value of $27.26 per share)			177,641
Stock options assumed (652,000 options)			9,478
Debt retired			106,700
Total		$	465,348
Allocation of purchase price:
Working capital deficit		$	(13,557	)
Other long-term assets			55
Oil and gas properties			487,345
Assets held for sale			140,000
Deferred income taxes			(147,062	)
Asset retirement obligations			(1,433	)
Total		$	465,348

     The following unaudited pro forma data includes the results of operations as if the Stroud acquisition had been consummated at the beginning of 2006. See also Note 4 for discontinued operations. The pro forma data is based on historical information and does not necessarily reflect the actual results that would have occurred, nor are they necessarily indicative of future results of operations (in thousands, except per share data).

		Three Months
		Ended March 31,
		2006
Revenues		$	197,237
Income from continuing operations			53,674
Net income			58,547
Per share data:
Income from continuing operations – basic		$	0.40
Income from continuing operations – diluted			0.38
Net income – basic		$	0.43
Net income – diluted			0.42

     In February 2007, we sold our Austin Chalk properties for proceeds of $80.4 million. These properties were originally acquired in mid-2006 as part of our Stroud acquisition and were classified as assets held for sale since the acquisition date. On March 30, 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. The properties included our interests in 37 platforms in water depths ranging from 11 to 240 feet. None of these Gulf of Mexico properties were operated by Range. Both dispositions are subject to typical post-closing adjustments (see also Note 4).

(4) 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. As of March 30, 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. Discontinued operations for the three months ended March 31, 2007 and 2006 are summarized as follows (in thousands):

		Three Months Ended
		March 31,
		2007				2006
Revenues:
Oil and gas sales		$	16,283			$	9,783
Transportation and gathering			68				116
Other			310				(1	)
Gain on disposition of assets and other			93,461				—
			110,122				9,898
Costs and expenses:
Direct operating			2,757				1,529
Production and ad valorem taxes			141				176
Exploration and other			66				1,155
Interest expense			845				317
Depletion, depreciation and amortization			6,672				2,916
			10,481				6,093
Income from discontinued operations before income taxes			99,641				3,805
Income tax expense			34,873				1,332
Income from discontinued operations, net of taxes		$	64,768			$	2,473
Production:
Crude oil (bbls)			40,634				26,184
Natural gas (mcf)			1,990,276				1,156,401
Total (mcfe)			2,234,084				1,313,506

(5) INCOME TAXES

     The significant components of deferred tax liabilities and assets on March 31, 2007 and December 31, 2006 were as follows (in thousands):

		March 31,				December 31,
		2007				2006
Deferred tax assets (liabilities)
Net unrealized gain in OCI		$	1,421			$	(21,264	)
Net operating loss carryover and other			125,476				100,520
Depreciation and depletion			(612,176	)			(547,899	)
Net deferred tax liability		$	(485,279	)		$	(468,643	)

     At December 31, 2006, we had regular net operating loss (“NOL”) carryovers of $229.6 million and alternative minimum tax (“AMT”) NOL carryovers of $192.4 million that expire between 2012 and 2026. At December 31, 2006, we had AMT credit carryovers of $700,000 that are not subject to limitation or expiration. We anticipate that a significant portion of our NOL will be used in conjunction with the sale of our Gulf of Mexico properties.

(6) 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,
		2007				2006
Numerator:
Income from continuing operations		$	8,369			$	53,202
Income from discontinued operations, net of taxes			64,768				2,473
Net income			73,137				55,675
Denominator:
Weighted average shares outstanding			139,213				130,742
Stock held in the deferred compensation plan and restricted stock			(1,111	)			(1,650	)
Weighted average shares, basic			138,102				129,092
Effect of dilutive securities:
Weighted average shares outstanding			139,213				130,742
Employee stock options, SARs and other			4,017				3,811
Treasury shares		—				(4)
Dilutive potential common shares for diluted earnings per share			143,230				134,549
Earnings per common share basic and diluted:
Basic – income from continuing operations		$	0.06			$	0.41
– discontinued operations			0.47				0.02
– net income			0.53				0.43
Diluted – income from continuing operations		$	0.06			$	0.40
– discontinued operations			0.45				0.01
– net income			0.51				0.41

     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.

(7) SUSPENDED EXPLORATORY WELL COSTS

     The following table reflects the changes in capitalized exploratory well costs for the three months ended March 31, 2007 and the year ended December 31, 2006 (in thousands):

		March 31, 2007				December 31, 2006
Beginning balance at January 1		$	9,984			$	25,340
Additions to capitalized exploratory well costs pending the determination of proved reserves			3,868				4,695
Reclassifications to wells, facilities and equipment based on determination of proved reserves			—				(16,710	)
Capitalized exploratory well costs charged to expense			(4,135	)			(3,341	)
Divested wells			(1,325	)			—
Balance at end of period			8,392				9,984
Less exploratory well costs that have been capitalized for a period of one year or less			(8,392	)			(4,792	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$	—			$	5,192
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			—				3

     The $8.4 million of capitalized exploratory well costs at March 31, 2007 was incurred in 2007 ($3.9 million) and in 2006 ($4.5 million).

(8) INDEBTEDNESS

     We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at March 31, 2007 is shown parenthetically). No interest expense was capitalized during the three months ended March 31, 2007 and 2006.

		March 31,				December 31,
		2007				2006
Bank debt (6.5%)		$	537,500			$	452,000
Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount			197,346				197,262
6.375% Senior Subordinated Notes due 2015			150,000				150,000
7.5% Senior Subordinated Notes due 2016, net of discount			249,528				249,520
Total debt		$	1,134,374			$	1,048,782

Bank Debt

     In October 2006, we entered into an amended and restated $800.0 million revolving bank facility, which we refer to as our bank debt or 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 an $800.0 million facility amount or the borrowing base. On March 23, 2007, the facility amount was increased to $900.0 million and the borrowing base was redetermined as $1.2 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, 2007, the outstanding balance under the bank credit facility was $537.5 million and there was $362.5 million of borrowing capacity available. On March 30, 2007, we received cash proceeds of $155.0 million from the sale of our Gulf of Mexico properties. These proceeds were used to pay down the credit facility in April. The loan matures October 25, 2011. 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 (A) 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 6.4% for the three months ended March 31, 2007 compared to 5.6% for the three months ended March 31, 2006. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At March 31, 2007, the commitment fee was 0.25% and the interest rate margin was 1.0%. At April 24, 2007, the interest rate (including applicable margin) was 7.0%.

Senior Subordinated Notes

     In 2003, we issued $100.0 million aggregate principal amount of 7.375% senior subordinated notes due 2013 (“7.375% Notes”). In 2004, we issued an additional $100.0 million of 7.375% Notes; therefore, $200.0 million of the 7.375% Notes are currently outstanding. The 7.375% Notes were issued at a discount which will be amortized into interest expense over the life of the 7.375% Notes. In 2005, we issued $150.0 million of 6.375% senior subordinated notes due 2015 (“6.375% Notes”). In May 2006, we issued $150.0 million of the 7.5% senior subordinated notes due 2016 (“7.5% Notes”). In August 2006, we issued an additional $100.0 million of the 7.5% Notes; therefore, $250.0 million of the 7.5% Notes are currently outstanding. Interest on our senior subordinated notes is payable semi-annually and each of the notes are guaranteed by certain of our subsidiaries.

     We may redeem the 7.375% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices of 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. We may redeem the 6.375% Notes, in whole or in part, at any time on or after March 15, 2010, at redemption prices from 103.2% of the principal amount as of March 15, 2010 and declining to 100% on March 15, 2013 and thereafter. Prior to March 15, 2008, we may redeem up to 35% of the original aggregate principal amount of the 6.375% Notes at a redemption price of 106.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. We may redeem the 7.5% Notes, in whole or in part, at any time on or after May 15, 2011 at redemption prices from 103.75% of the principal amount as of May 15, 2011 and declining to 100% on May 15, 2014 and thereafter. Prior to May 15, 2009, we may redeem up to 35% of the original aggregate principal amount of the 7.5% Notes at a redemption price of

107.5% of 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 our 7.5% Notes remains outstanding immediately after the occurrence of such redemption and provided that such redemption occurs within 60 days of the date of closing the equity sale.

     If we experience a change of control, there may be a requirement to repurchase all or a portion of the senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank credit facility and the indentures governing the subordinated notes.

Subsidiary Guarantors

     Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees of the 7.5% Notes, the 7.375% Notes and the 6.375% Notes are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.

Debt Covenants

     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at March 31, 2007. Under the bank credit facility, dividends are permitted, subject to the provisions of the restricted payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances. Approximately $482.2 million was available under the bank credit facility’s restricted payment basket on March 31, 2007. The terms of each of our subordinated notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings and equity issuances since the original issuance of the notes. The 7.5% Notes also allows for any cash proceeds received from the sale of oil and gas property purchased in the Stroud acquisition to be added to the restricted payment basket. At March 31, 2007, $559.1 million was available under the restricted payment baskets for each of the 7.375% Notes and the 6.375% Notes. There was $640.1 million available under the 7.5% Notes restricted payment basket.

(9) ASSET RETIREMENT OBLIGATIONS

     A reconciliation of our liability for plugging and abandonment costs for the three months ended March 31, 2007 and 2006 is as follows (in thousands):

		Three Months Ended
		March 31,
		2007				2006
Beginning of period		$	95,588			$	68,063
Liabilities incurred			1,148				686
Liabilities settled			(291	)			(510	)
Disposition of wells			(20,912	)			—
Accretion expense – continuing operations			1,259				834
Accretion expense – discontinued operations			375				248
Change in estimate			—				405
End of period		$	77,167			$	69,726

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

(10) 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 schedule of changes in the number of common shares outstanding:

		Three Months				Year
		Ended				Ended
		March 31, 2007				December 31, 2006
Beginning balance			138,931,565				129,907,220
Shares issued for Stroud acquisition			—				6,517,498
Stock options/SARs exercised			618,064				1,956,164
Restricted stock grants			10,000				474,609
Deferred compensation plan			13,570				12,998
In lieu of bonuses			29,483				20,686
Contributed to 401(k) plan			—				36,564
Treasury shares			—				5,826
			671,117				9,024,345
Ending balance			139,602,682				138,931,565

Treasury Stock

     The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities.

(11) DERIVATIVE ACTIVITIES

     At March 31, 2007, we had open swap contracts covering 66.2 Bcf of gas at prices averaging $9.18 per mcf. We also had collars covering 47.2 Bcf of gas at weighted average floor and cap prices which range from $7.28 to $10.35 per mcf and 5.9 million barrels of oil at weighted average floor and cap prices that range from $57.76 to $72.53 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, 2007, was a net unrealized pre-tax gain of $21.6 million. These contracts expire monthly through December 2009. Transaction gains and gains on settled contracts are determined monthly and are included as increases or decreases to oil and gas revenues in the period the hedged production is sold. Oil and gas revenues were increased by gains of $35.5 million in the first three months of 2007 compared with losses of $17.1 million in the three months ended March 31, 2006. Other revenues in our consolidated statement of operations include ineffective hedging losses on hedges that qualified for hedge accounting of $219,000 in the first three months of 2007 compared with gains of $1.4 million in the three months ended March 31, 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting and are marked to market. This resulted in a loss of $66.1 million in the first quarter of 2007 compared to a gain of $11.3 million in the first three months of 2006.

     The following table sets forth our derivative volumes by year as of March 31, 2007:

						Average Hedge
Period		Contract Type		Volume Hedged		Price
Natural Gas
2007		Swaps		100,864 Mmbtu/day		$8.85
2007		Collars		98,500 Mmbtu/day		$6.79 - $9.57
2008		Swaps		105,000 Mmbtu/day		$9.42
2008		Collars		55,000 Mmbtu/day		$7.93 - $11.40
Crude Oil
2007		Collars		6,300 bbl/day		$53.46 - $65.33
2008		Collars		8,500 bbl/day		$59.01 - $75.36
2009		Collars		3,000 bbl/day		$61.00 - $75.89

     The combined fair values of net unrealized gains on oil and gas derivatives totaled $21.6 million and appear as unrealized derivative gains and losses on the balance sheet. Hedging 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. The creditworthiness of the counterparties is subject to continuing review.

(12) 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 of the Board of Directors which is made up of independent 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
		Shares				Exercise Price
Outstanding on December 31, 2006			8,852,126			$	12.76
Granted			1,085,775				31.43
Exercised			(710,514	)			11.15
Expired/forfeited			(112,599	)			25.09
Outstanding on March 31, 2007			9,114,788			$	14.96

     The following table shows information with respect to outstanding stock options and SARs at March 31, 2007:

						Outstanding												Exercisable
										Weighted-												Weighted-
										Average				Weighted-								Average
										Remaining				Average								Exercise
Range of Exercise Prices						Shares				Contractual Life				Exercise Price				Shares				Price
$			1.29–$4.99				2,387,457				2.71			$	3.63				2,387,457			$	3.63
			5.00 – 9.99				1,169,298				1.88				7.01				1,156,698				7.01
			10.00 – 14.99				351,988				2.61				11.53				181,347				12.25
			15.00 – 19.99				2,525,046				3.30				16.88				1,416,564				17.00
			20.00 – 24.99				1,485,049				4.01				24.22				424,267				24.26
			25.00 – 29.99				145,500				4.02				26.44				21,150				25.85
			30.00 – 33.23				1,050,450				4.89				31.43				—				—
		Total					9,114,788				3.25			$	14.96				5,587,483			$	9.65

     The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2007 was $10.00. The fair value of each stock option/SAR granted during 2007 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 4.72%; dividend yield of 0.38%; expected volatility of 36%; and an expected life of 3.55 years.

     As of March 31, 2007, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $168.1 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $132.7 million and 2.84 years. As of March 31, 2007, the number of fully-vested awards and awards expected to vest was 8.9 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $14.68 and 3.2 years and the aggregate intrinsic value was $166.2 million. As of March 31, 2007, unrecognized compensation cost related to the awards was $22.9 million, which is expected to be recognized over a weighted average period of 1.4 years.

Restricted Stock Grants

     During the first quarter of 2007, 10,000 shares of restricted stock were issued to employees at an average price of $31.00 and have a three-year vesting period. In the first quarter of 2006, we issued 328,600 shares of restricted stock as compensation to directors and employees at an average price of $24.32. 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 $1.2 million in the first three months of 2007 compared to $472,000 in the three-month period ended March 31, 2006. As of March 31, 2007, unrecognized compensation cost related to these restricted stock awards was $11.5 million, which is expected to be recognized over the next 3 years.

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 held in the Rabbi Trust is treated in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability and the carrying value of the deferred compensation liability 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. The deferred compensation liability on our balance sheet reflects the market value of the securities held in the Rabbi Trust. The cost of common stock held in the Rabbi Trust is shown as a reduction to stockholders’ equity. Changes in the market value of the marketable securities are reflected in other comprehensive income (“OCI”), while changes in the market value of the Range common stock held in the Rabbi Trust is charged or credited to deferred compensation plan expense each quarter. We recorded non-cash mark-to-market expense related to our deferred compensation plan of $11.2 million in the first three months of 2007 compared to $4.5 million in the three months ended March 31, 2006.

(13) SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended
		March 31,
		2007				2006
		(in thousands)
Non-cash investing and financing activities included:
Common stock issued under benefit plans		$	1,344			$	891
Asset retirement costs capitalized			1,123				1,091
Net cash provided from operating activities included:
Income taxes paid (refunded)		$	10			$	(1,972	)
Interest paid			20,324				16,138

(14) 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.

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

		March 31,				December 31,
		2007				2006
		(in thousands)
Oil and gas properties:
Properties subject to depletion		$	3,560,308			$	3,414,964
Unproved properties			237,848				226,263
Total			3,798,156				3,641,227
Accumulated depreciation, depletion and amortization			(1,008,306	)			(964,551	)
Net capitalized costs		$	2,789,850			$	2,676,676

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

		Three Months				Year
		Ended				Ended
		March 31,				December 31,
		2007				2006
		(in thousands)
Acquisitions:
Acreage purchases		$	17,600			$	79,762
Unproved leasehold			—				132,821
Proved oil and gas properties			31,434				209,262
Purchase price adjustment (b)			—				147,062
Asset retirement obligations			—				896
Development (d)			166,485				464,586
Exploration (c) (d)			17,288				70,870
Gas gathering facilities (d)			3,334				19,690
Subtotal			236,141				1,124,949
Asset retirement obligations			1,123				25,821
Total costs incurred		$	237,264			$	1,150,770

(17) NEW ACCOUNTING STANDARD

     In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN48”). FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes,” and seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes. In addition, FIN 48 provides guidance on de-recognition, classification, interest and penalties, and accounting in interim periods and requires expanded disclosure with respect to the uncertainty in income taxes.

     We adopted the provisions of FIN 48 on January 1, 2007. There was no cumulative effect as a result of applying FIN 48. No adjustment was made to our opening balance of retained earnings. We have approximately $600,000 of unrecognized tax benefits recorded as of the date of adoption.

     We file consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to US Federal income tax examinations for years after 2002 and we are subject to various state tax examinations for years after 2001.

     Our continuing practice is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties as of March 31, 2007.

(18) SUBSEQUENT EVENTS

     On April 13, 2007, we entered into certain agreements, with certain subsidiaries of Equitable Resources, Inc. (“Equitable”), with respect to a development plan for the Nora field, a gas field located in southwestern Virginia. Range and Equitable both own interests in the Nora field, which currently encompasses approximately 1,600 producing wells and 300,000 gross acres. Under the plan, Equitable and Range will equalize their interests in the Nora field, including the producing wells, undrilled acreage and a gathering system. We entered into a Purchase and Sale Agreement (the “Purchase Agreement”), pursuant to which we will acquire one-half of Equitable’s interest in leases on the Nora field (subject to specific exclusions) as well as new and additional incremental interest in existing wells in the Nora field (the “Acquisition”). The oil and gas property Acquisition purchase price is $262 million, subject to certain adjustments. The pipeline and

gathering system acquisition price is $53.0 million. The Purchase Agreement contains customary representations, warranties and covenants by each of Range and Equitable.

     The Purchase Agreement is subject to termination by mutual agreement of Range and Equitable, by either party if the Acquisition is not closed by June 12, 2007, or by either party if (subject to the other party’s right to cure) the representations and warranties of the other party contained in the Purchase Agreement shall not be true and correct in all material respects, or the other party breaches, in any material respect, any of its obligations under the Purchase Agreement.

     On April 17, 2007, we entered into an underwriting agreement to sell 7,000,000 shares of common stock at $36.28 per share, subject to an over-allotment option for a period of 30 days to purchase an additional 1,050,000 shares. The proceeds of the offering will be used to fund a portion of the Equitable transaction. Pending such use, the proceeds will be used to pay down a portion of the outstanding balance on our credit facility. On April 23, 2007, the underwriters exercised the over-allotment option, the offering of the common stock closed and we received $280.4 million of proceeds from the sale of 8,050,000 shares of common stock.

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 2006 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 in our 2006 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, 2006.

Results of Continuing Operations

Volumes and sales data

		Three Months Ended
		March 31,
		2007				2006
Production:
Crude oil (bbls)			838,488				743,511
NGLs (bbls)			273,130				267,053
Natural gas (mcf)			19,694,023				15,763,705
Total (mcfe) (a)			26,363,731				21,827,089
Average daily production:
Crude oil (bbls)			9,316				8,261
NGLs (bbls)			3,035				2,967
Natural gas (mcf)			218,822				175,152
Total (mcfe) (a)			292,930				242,523
Average sales prices (excluding hedging):
Crude oil (per bbl)		$	56.00			$	59.74
NGLs (per bbl)		$	30.13			$	29.77
Natural gas (per mcf)		$	6.42			$	8.33
Total (per mcfe) (a)		$	6.88			$	8.11
Average sales price (including hedging):
Crude oil (per bbl)		$	55.99			$	46.54
NGLs (per bbl)		$	30.13			$	29.77
Natural gas (per mcf)		$	8.22			$	7.86
Total (per mcfe) (a)		$	8.23			$	7.63
Average NYMEX prices (b)
Oil (per bbl)		$	58.27			$	63.48
Natural gas (per mcf)		$	6.96			$	9.07

Overview

     Revenues decreased 15% for the first quarter of 2007 over the same period of 2006. This decrease is due to an unfavorable mark-to-market value adjustment on oil and gas derivatives that do not qualify for hedge accounting partially offset by higher production and realized prices. For the first quarter of 2007, production increased 21% due to the continued success of our drilling program and our acquisitions. Realized oil and gas prices were higher by 8% in the first quarter of 2007 compared to the same period of 2006 reflecting the expiration of lower priced oil and gas hedges. Our remaining hedges increased revenue by $35.5 million in the first three months of 2007 compared to a decrease of $17.1 million in the same period of 2006.

     Higher production volumes and higher oil and gas prices have improved our profit margins. However, Range and the oil and gas industry as a whole continues to experience higher operating costs due to heightened competition for qualified employees, goods and services. On a unit cost basis, our direct operating costs increased $0.13 per mcfe, a 16% increase from the first quarter of 2006 to the first quarter of 2007. It is anticipated that service and personnel costs will remain high as oil and gas industry fundamentals remain favorable.

     On March 30, 2007, we sold our Gulf of Mexico properties. For the three months ended March 31, 2007 and 2006, these operations are shown in discontinued operations.

Comparison of Quarter Ended March 31, 2007 and 2006

     Oil and gas revenue for the three months ended March 31, 2007 and 2006 (in thousands) is summarized in the following table:

		Three Months Ended March 31,
		2007				2006				Change				%
Oil and Gas Revenues:
Oil wellhead		$	46,961			$	44,418			$	2,543				6	%
Oil hedges			(12	)			(9,821	)			9,809				100	%
Total oil revenue		$	46,949			$	34,597			$	12,352				36	%
Gas wellhead		$	126,324			$	131,242			$	(4,918	)			4	%
Gas hedges			35,524				(7,234	)			42,758				591	%
Total gas revenue		$	161,848			$	124,008			$	37,840				31	%
NGL		$	8,229			$	7,950			$	279				4	%
NGL hedges			—				—				—				—	%
Total NGL revenue		$	8,229			$	7,950			$	279				4	%
Combined wellhead		$	181,514			$	183,610			$	(2,096	)			1	%
Combined hedges			35,512				(17,055	)			52,567				308	%
Total oil and gas revenue		$	217,026			$	166,555			$	50,471				30	%

     Average realized prices received for oil and gas during the first quarter of 2007 was $8.23 per mcfe, up 8% or $0.60 per mcfe from the same quarter of the prior year. The average price received in the first quarter for oil increased 20% to $55.99 per barrel and increased 5% to $8.22 per mcf for gas from the same period of 2006. The effect of our hedging program increased realized prices $1.35 per mcfe in the first quarter of 2007 versus a decrease of $0.78 per mcfe in the same period of 2006.

     Production volumes increased 21% from the first quarter of 2006 primarily due to continued drilling success and our acquisitions. Our production for the first quarter was 292.9 Mmcfe per day of which 61% was attributable to our Southwestern division, 36% to our Appalachian division and 3% to our Gulf Coast division.

     Mark-to-market on oil and gas derivatives includes a loss of $66.1 million in 2007 compared to a gain of $11.3 million in the same period of 2006. In the fourth quarter of 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. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from ineffective hedges are not included in other comprehensive income. Because gas prices increased in the first quarter, our hedges became comparatively less valuable. However, we expect these losses will be offset by higher revenues in the future.

     Transportation and gathering revenue of $184,000 increased $223,000 from 2006. This increase is primarily due to higher processing margins.

     Other revenue increased in 2007 to $1.7 million from $1.4 million in 2006. The 2007 period includes insurance proceeds of $1.0 million and income from equity method investments of $411,000 somewhat offset by $219,000 of ineffective hedging losses. Other revenue for 2006 includes $1.4 million of ineffective hedging gains.

     Our operating expenses have increased as we continue to grow. We believe most of our operating expense fluctuations are best analyzed on a unit-of-production, or per mcfe basis. The following presents information about our operating expenses on an mcfe basis for the three months ended March 31, 2007 and 2006:

Operating expenses per mcfe		2007				2006				Change				%
Direct operating expense (excluding $0.01 per mcfe stock-based compensation in 2007 and $0.01 per mcfe in 2006)		$	0.95			$	0.82			$	0.13				16	%
Production and ad valorem tax expense			0.39				0.44				(0.05	)			11	%
General and administrative expense (excluding stock-based compensation of $0.14 per mcfe in 2007 and $0.11 per mcfe in 2006)			0.42				0.41				0.01				2	%
Interest expense			0.71				0.47				0.24				51	%
Depletion, depreciation and amortization expense			1.80				1.45				0.35				24	%

     Direct operating expense (excluding stock-based compensation) increased $7.2 million in the first quarter of 2007 to $25.0 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 $1.4 million ($0.05 per mcfe) of workover costs in 2007 versus $599,000 ($0.03 per mcfe) in 2006. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) increased $0.13 per mcfe from the same period of 2006 with the increase consisting primarily of higher water disposal costs ($0.07 per mcfe) and higher well service costs ($0.06 per mcfe).

     Production and ad valorem taxes are paid based on market prices, not hedged prices. These taxes increased $861,000 million or 9% from the same period of the prior year due to higher volumes offset by lower prices and assessed values. On a per mcfe basis, production and ad valorem taxes decreased to $0.39 per mcfe in 2007 from $0.44 per mcfe in the same period of 2006.

     General and administrative expense (excluding stock-based compensation) for the first quarter of 2007 increased $2.1 million from 2006 due to higher salaries and benefits ($1.5 million), higher office rent and general office expense ($211,000) and higher franchise taxes ($139,000). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.41 per mcfe in 2006 to $0.42 per mcfe in the first quarter 2007.

     Interest expense for the first quarter of 2007 increased $8.6 million to $18.8 million due to rising interest rates and the refinancing of certain debt from floating to higher fixed rates in the second and third quarters of 2006. In 2006, we issued $250.0 million of 7.5% Notes which added $4.7 million of interest costs in the first quarter of 2007. The proceeds from the issuance of the 7.5% Notes were used to retire lower interest bank debt and to better match the maturities of our debt with the life of our properties. Average debt outstanding on the bank credit facility for the first quarter of 2007 was $507.4 million compared to $278.6 million for the first quarter of 2006 and the average interest rates were 6.4% in the first quarter of 2007 compared to 5.6% in the same quarter of the prior year.

     Depletion, depreciation and amortization (“DD&A”) increased $15.7 million or 50% to $47.3 million in the first quarter of 2007 with a 21% increase in production and a 25% increase in depletion rates. The increase in DD&A per mcfe is related to our Stroud acquisition, increasing drilling costs and the mix of our production. On a per mcfe basis, DD&A increased from $1.45 per mcfe in the first quarter of 2006 to $1.80 per mcfe in the first quarter of 2007.

     Operating expenses also include stock-based compensation, exploration expense and non-cash deferred compensation plan expenses that generally do not trend with production. In 2006 and 2007, stock-based compensation represents the amortization of restricted stock grants and expenses related to the adoption of SFAS No. 123(R). In 2007, stock-based compensation is a component of direct operating expense ($398,000), exploration expense ($739,000), general and administrative expense ($3.6 million) and a $93,000 reduction of net gas transportation revenues for a total of $4.9 million. In 2006, stock-based compensation is a component of direct operating expense ($285,000), exploration expense ($609,000), general and administrative expense ($2.4 million) and a $65,000 reduction of net gas transportation revenues for a total of $3.3 million.

     Exploration expense increased $2.8 million due to higher dry hole costs. The following table details our exploration-related expenses for the three months ended March 31, 2007 and 2006 (in thousands):

Exploration expenses		2007				2006				Change				%
Dry hole expense		$	4,408			$	1,700			$	2,708				159	%
Seismic			3,476				4,452				(976	)			22	%
Personnel expense			1,997				1,549				448				29	%
Stock-based compensation expense			739				609				130				21	%
Other			1,090				612				478				78	%
Total exploration expense		$	11,710			$	8,922			$	2,788				31	%

     Deferred compensation plan expense for the first quarter of 2007 increased $6.8 million from 2006 due to an increase in our stock price. Our stock price increased from $27.46 at December 31, 2006 to $33.40 at March 31, 2007. This non-cash expense relates to the increase or decrease in value of our common stock and other investments held in our deferred compensation plans.

     Income tax expense for 2007 decreased to $4.8 million reflecting the 84% decrease in income from continuing operations before taxes compared to the same period of 2006. The first quarter of 2007 and 2006 provide for a tax expense at an effective rate of approximately 37%. Current income taxes of $384,000 represent state income taxes.

     Discontinued operations include the operating results related to our Gulf of Mexico properties and Austin Chalk properties that we sold in the first quarter of 2007. We recorded a pre-tax gain on sale of our Gulf of Mexico properties of $95.6 million. The first quarter of 2007 and 2006 provide for a tax expense at an effective rate of approximately 35%. See also Note 4 to our consolidating financial statements.

Liquidity and Capital Resources

     During the three months ended March 31, 2007, our cash provided from continuing operations was $84.1 million and we spent $239.2 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $86.0 million. At March 31, 2007, we had $167.9 million in cash, total assets of $3.3 billion and a debt-to-capitalization ratio of 46.6%. The cash balance includes proceeds received from the March 30, 2007 sale of our Gulf Coast properties of $155.0 million. These proceeds were used to pay down our credit facility balance in April. Long-term debt at March 31, 2007 totaled $1.1 billion including $537.5 million of bank credit facility debt and $596.9 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at March 31, 2007 was $362.5 million. On April 23, 2007, we received $280.4 million of proceeds from the sale of 8,050,000 shares of common stock. These proceeds were used to pay down a portion of our outstanding balance on our credit facility and will be used to fund a portion of the proposed Equitable transaction.

     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.

Bank Debt

     The debt agreements contain covenants relating to working capital, dividends and financial ratios. We were in compliance with all covenants at March 31, 2007. Under the bank credit facility, common and preferred dividends are permitted, subject to the terms of the restricted payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances occurring since December 31, 2001. Approximately $482.2 million was available under the bank credit facility’s restricted payment basket on March 31, 2007. The terms of our senior subordinated notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings since the issuance of the notes and 100% of net cash proceeds from common stock issuances. The 7.5% Notes also allow for any cash proceeds received from the sale of oil and gas properties purchased in the Stroud acquisition to be added to the restricted payment baskets. Approximately $559.1 million was available under each of the 7.375% Notes and the 6.375% Notes restricted payment basket on March 31, 2007. There was $640.1 million available under the 7.5% Note restricted payment baskets.

     We maintain a $900.0 million revolving bank credit facility. The facility is secured by substantially all our assets. Availability under the facility is subject to a borrowing base set by the banks semi-annually and in certain other circumstances more frequently. The borrowing base in dependent on a number of factors, primarily the lenders assessment of future cash flows. Redeterminations, other than increases, require the approval of 75% of the lenders while increases require unanimous approval. At April 24, 2007, the bank credit facility had a $1.2 billion borrowing base and an $900.0 million facility amount. Credit availability is equal to the lesser of the facility amount or the borrowing base resulting in credit availability of $758.5 million on April 24, 2007.

Cash Flow

     Our principal sources of cash are operating cash flow and bank borrowings and at times, the sale of assets and the issuance of debt and equity securities. Our operating cash flow is highly dependent on oil and gas prices. As of March 31, 2007, we have entered into hedging agreements covering 65.2 Bcfe, 77.2 Bcfe and 6.6 Bcfe for 2007, 2008 and 2009, respectively. Net cash provided from continuing operations for the three months ended March 31, 2007 was $84.1 million compared to $116.4 million in the three months ended March 31, 2006. Cash flow from operations was lower than the prior year due to timing of working capital changes. Net cash used in investing for the three months ended March 31, 2007 was $12.2 million compared to $107.4 million in the same period of 2006. The 2007 period includes $182.8 million of additions to oil and gas properties, $49.1 million of acquisitions offset by proceeds of $234.3 million from asset sales. The 2006 period included $91.1 million of additions to oil and gas properties and $10.0 million of acquisitions. Net cash provided from financing for the three months ended March 31, 2007 was $86.0 million compared to net cash used in financing of $21.5 million in the first three months of 2006. This increase was primarily the result of borrowings under our credit facility. During the first three months of 2007 total debt increased $85.6 million.

Dividends

     On March 1, 2007, the Board of Directors declared a dividend of three cents per share ($4.2 million) on our common stock, payable on March 30, 2007 to stockholders of record at the close of business on March 15, 2007.

Capital Requirements and Contractual Cash Obligations

     The 2007 capital budget is currently set at $822.0 million (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, 2007, $183.8 million of development and exploration spending was funded with internal cash flow and borrowings under our credit facility.

     Other than our pending development plan with respect to the Nora field (as discussed in Note 18 to the consolidated financial statements), there have been no significant changes to our contractual obligations subsequent to December 31, 2006. The proposed Nora field acquisition purchase price is approximately $315.0 million. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2006.

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 the liquidity or consolidated financial position of Range.

Hedging – Oil and Gas Prices

     We enter into hedging agreements to reduce the impact of oil and gas price volatility on our operations. At March 31, 2007, swaps were in place covering 66.2 Bcf of gas at prices averaging $9.18 per mcf. We also have collars covering 47.2 Bcf of gas at weighted average floor and cap prices which range from $7.28 to $10.35 per mcf and 5.9 million barrels of oil at weighted average floor and cap prices that range from $57.76 to $72.53 per barrel. Their fair value at March 31, 2007 (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 gain of $21.6 million. Gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. An ineffective portion (changes in contract prices that do not match changes in the hedge price) of open hedge contracts is recognized in earnings quarterly in other revenue. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting and are marked to market. In the first quarter of 2007, this resulted in a loss of $66.1 million compared to a gain of $11.3 million in the first quarter of 2006.

     At March 31, 2007, the following commodity derivative contracts were outstanding:

						Average
Period		Contract Type		Volume Hedged		Hedge Price
Natural Gas
2007		Swaps		100,864 Mmbtu/day		$	8.85
2007		Collars		98,500 Mmbtu/day		$ 6.79 - $9.57
2008		Swaps		105,000 Mmbtu/day		$	9.42
2008		Collars		55,000 Mmbtu/day		$ 7.93 - $11.40
Crude Oil
2007		Collars		6,300 bbl/day		$ 53.46 - $65.33
2008		Collars		8,500 bbl/day		$ 59.01 - $75.36
2009		Collars		3,000 bbl/day		$ 61.00 - $75.89

Interest Rates

     At March 31, 2007, we had $1.1 billion of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Bank debt totaling $537.5 million bears interest at floating rates, which average 6.5% at March 31, 2007. The 30 day LIBOR rate on March 31, 2007 was 5.3%.

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 the first quarter of 2007, we received an average of $56.00 per barrel of oil and $6.42 per mcf of gas before hedging compared to $59.74 per barrel of oil and $8.33 per mcf of gas in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during 2005 and 2006, 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 2007.

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 US 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 hedging 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 establish a minimum floor price and a predetermined ceiling price. Realized gains or losses are recognized in oil and gas revenue when the associated production occurs. Gains or losses on open contracts are recorded either in current period income or other comprehensive income. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying commodity transaction. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying commodity transaction. Ineffective gains and losses are recognized in earnings in other revenues. We do not enter into derivative instruments for trading purposes. Though not all of our derivatives qualify as accounting hedges, the purpose of entering into the contracts is to economically hedge oil and gas prices. Those that do not qualify as accounting hedges are marked to market through current period income.

     As of March 31, 2007, we had gas swaps in place covering 66.2 Bcf of gas. We also had collars covering 47.2 Bcf of gas and 5.9 million barrels of oil. Their fair value, represented by the estimated amount that would be realized upon immediate liquidation, based on contract versus NYMEX prices, approximated a net unrealized pre-tax gain of $21.6 million at that date. These contracts expire monthly through December 2009. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price received by us for the sale of our hedged production and the hedge price, generally closing prices on the NYMEX. Net realized gains relating to these derivatives for the three months ended March 31, 2007 was $35.5 million compared to losses of $17.1 million in the first three months of 2006. Losses or gains due to commodity hedge ineffectiveness are recognized in earnings in other revenues in our consolidated statement of operations. The ineffective portion of hedges was a loss of $219,000 in the first three months of 2007 compared to a gain of $1.4 million in the first three months of 2006.

     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. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the volatility in gas prices and its effect on our basis differentials and are marked to market. This resulted in a loss of $66.1 million in the first three months of 2007 compared to a gain of $11.3 million in the same period of 2006.

     At March 31, 2007, the following commodity derivative contracts were outstanding:

						Average				Fair
Period		Contract Type		Volume Hedged		Hedge Price				Market Value
										(In thousands)
Natural Gas
2007		Swaps		100,864 Mmbtu/day		$	8.85			$	15,778
2007		Collars		98,500 Mmbtu/day		$ 6.79 - $9.57				$	(6,593	)
2008		Swaps		105,000 Mmbtu/day		$	9.42			$	26,387
2008		Collars		55,000 Mmbtu/day		$ 7.93 - $11.40				$	4,744
Crude Oil
2007		Collars		6,300 bbl/day		$ 53.46 - $65.33				$	(12,530	)
2008		Collars		8,500 bbl/day		$ 59.01 - $75.36				$	(5,773	)
2009		Collars		3,000 bbl/day		$ 61.00 - $75.89				$	(420	)

     In the first three months of 2007, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $17.9 million. If oil and gas future prices at March 31, 2007 declined 10%, the unrealized hedging gain at that date would have increased by $82.6 million.

     Interest rate risk. At March 31, 2007, we had $1.1 billion of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Senior debt totaling $537.5 million bore interest at floating rates averaging 6.5%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $5.4 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 13a-15(e) of 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 1A. Risk Factors

Our pending Equitable transaction may not close as anticipated

     The closing of the Equitable transaction is subject to Hart-Scott-Rodino clearance and other customary closing conditions. We expect that the transaction will close in May 2007, but we cannot assure you that the transaction will close at such time or at all. This offering is not conditioned on the closing of the Equitable transaction, and we cannot predict the impact on our stock price if the Equitable transaction does not close.

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*			First Amendment to the Third Amended and Restated Credit Agreement dated October 25, 2006 among Range (as borrowers) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent
	10.2*			Second Amendment to the Third Amended and Restated Credit Agreement dated October 25, 2006 among Range (as borrowers) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent
	10.3			Purchase and Sale Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc. and Equitable Production Company (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 13, 2007)
	10.4			Contribution Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc., Equitable Production Company, Equitable Gathering Equity, LLC and Nora Gathering LLC (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 13, 2007)
	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

SIGNATURES

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

April 26, 2007

     Exhibit index

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*			First Amendment to the Third Amended and Restated Credit Agreement dated October 25, 2006 among Range (as borrowers) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent
	10.2*			Second Amendment to the Third Amended and Restated Credit Agreement dated October 25, 2006 among Range (as borrowers) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent
	10.3			Purchase and Sale Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc. and Equitable Production Company (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 13, 2007)
	10.4			Contribution Agreement, dated April 13, 2007, by and between Pine Mountain Oil and Gas, Inc., Equitable Production Company, Equitable Gathering Equity, LLC and Nora Gathering LLC (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on April 13, 2007)
	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

FIRST AMENDMENT TO
THIRD AMENDED AND RESTATED CREDIT AGREEMENT

     THIS FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment”) is entered into as of March 12, 2007, by and among RANGE RESOURCES CORPORATION, a Delaware corporation (“Borrower”), certain Subsidiaries of Borrower as Guarantors, JPMORGAN CHASE BANK, N.A., a national banking association as Administrative Agent for the Lenders (in such capacity, “Administrative Agent”), and each of the Lenders which is a party to the Credit Agreement (defined below).

WITNESSETH:

     WHEREAS, Borrower, Guarantors, Administrative Agent and the Lenders entered into that certain Third Amended and Restated Credit Agreement dated as of October 25, 2006 (as amended, modified and restated from time to time, the “Credit Agreement”), pursuant to which the Lenders made a revolving credit facility available to Borrower;

     WHEREAS, Range Energy Ventures Corporation, a Delaware corporation (“REVC”), and Range Offshore, L.P., an Ohio limited partnership (“ROLP”, and together with REVC, the “Targets”), are Subsidiaries of Borrower;

     WHEREAS, REVC is a Guarantor under the Credit Agreement and a Grantor under that certain Pledge and Security Agreement dated as of January 22, 2007 (the “Pledge Agreement”);

     WHEREAS, pursuant to the Pledge Agreement, all of the outstanding capital stock of REVC and certain of the outstanding Equity Interests in ROLP were pledged to Administrative Agent for the benefit of the Lenders;

     WHEREAS, Borrower proposes to dispose of certain assets pursuant to a sale which will be structured as a sale by Borrower, directly or indirectly, of all of the outstanding Equity Interests in the Targets to CIECO Energy (US) Limited (the “Offshore Sale”); and

     WHEREAS, Borrower has requested that Administrative Agent and the Lenders (a) consent to the Offshore Sale, (b) release REVC from its obligations as a Guarantor under the Credit Agreement and a Grantor under the Pledge Agreement, (c) release its Liens in (i) the Equity Interests of the Targets and (ii) any Collateral being sold in connection with the Offshore Sale which is pledged by the Targets under the Security Instruments, and (d) agree to make certain amendments to the Credit Agreement in connection therewith, and Administrative Agent and the Lenders have agreed to do so on the terms and conditions hereinafter set forth.

     NOW, THEREFORE, the parties agree to amend the Credit Agreement as follows:

     1. Definitions. Unless otherwise defined herein, all capitalized terms used herein shall have the same meanings ascribed to such terms in the Credit Agreement.

FIRST AMENDMENT TO THIRD AMENDED
AND RESTATED CREDIT AGREEMENT

2. Amendments to Credit Agreement.

     2.1 Mandatory Prepayment of Loans. Effective as of the First Amendment Effective Date, the first sentence of Section 2.12(b) of the Credit Agreement is hereby amended to read in its entirety as follows:

     (b) If the Borrower or any Restricted Subsidiary sells, transfers or otherwise disposes of any Borrowing Base Properties or the Equity Interests in any Restricted Subsidiary owning Borrowing Base Properties at any time a Borrowing Base Deficiency exists or would exist after giving effect to such sale, transfer or disposition, the Borrower shall prepay the Borrowings in an amount equal to the Net Cash Proceeds received from such sale, transfer or other disposition on the date it or any Restricted Subsidiary receives such Net Cash Proceeds; provided, however that amounts applied to the payment of Borrowings pursuant to this Section may be reborrowed subject to and in accordance with the terms of this Agreement.

     2.2 Fundamental Changes. Effective as of the First Amendment Effective Date, clause (vi) of Section 7.03(a) of the Credit Agreement is hereby amended to read in its entirety as follows:

(vi) subject to Section 2.12(b), the Borrower or any Restricted Subsidiary may sell, transfer, lease, exchange, abandon or otherwise dispose of Borrowing Base Properties (pursuant to a sale, transfer or other disposition of all, but not less than all, of the Equity Interests of any Restricted Subsidiary owning Borrowing Base Properties or otherwise); provided that the value of such Borrowing Base Properties (including the value of the Borrowing Base Properties sold, transferred or otherwise disposed of as a result of the sale, transfer or other disposition of all the Equity Interests of any such Restricted Subsidiary) sold, transferred, leased, exchanged, abandoned or otherwise disposed of between Scheduled Redeterminations does not exceed, in the aggregate for the Borrower and its Restricted Subsidiaries taken as a whole, ten percent (10%) of the Borrowing Base.

     2.3 Fundamental Changes. Effective as of the First Amendment Effective Date, Section 7.03 of the Credit Agreement is hereby further amended by adding the following subsections to the end thereof:

(c) In the event of a sale or other disposition of all or substantially all of the assets of any Guarantor or a sale or other disposition of all of the Equity Interests of any Guarantor by sale, merger or otherwise, in each case which sale or other disposition is permitted pursuant to Section 7.03(a)(vi), then effective upon the

FIRST AMENDMENT TO THIRD AMENDED
AND RESTATED CREDIT AGREEMENT

consummation of such sale or other disposition (i) such Guarantor shall be automatically released and relieved of any obligations as a Guarantor under Article VIII hereof, and (ii) Administrative Agent’s Liens in the Equity Interests of and Collateral owned by such Guarantor shall be automatically released.

(d) Administrative Agent shall execute any documents and instruments reasonably requested by Borrower from time to time in order to further evidence the release of Liens and guarantee pursuant to this Section 7.03.

     2.4 Waivers; Amendments. Effective as of the First Amendment Effective Date, clause (vi) of Section 11.02(b) of the Credit Agreement is hereby amended to read in its entirety as follows:

(vi) except in connection with any sales, transfers, leases, exchanges, abandonments or other dispositions permitted in Section 7.03, release any Credit Party from its obligations under the Loan Documents or release any of the Collateral without the written consent of each Lender, or

     3. Consent and Release. Effective as of the First Amendment Effective Date, Administrative Agent and the Lenders hereby consent to the Offshore Sale and effective upon the consummation of the Offshore Sale forever release and discharge (a) REVC from all obligations as a Guarantor under the Credit Agreement and a Grantor under the Pledge Agreement, and (b) all Liens in (i) the Equity Interests of the Targets and (ii) any Collateral being sold in connection with the Offshore Sale which is pledged by the Targets under the Security Instruments. Lenders authorize Administrative Agent or its designee to execute and deliver any Uniform Commercial Code termination statements and such other documents as may be necessary or appropriate to further evidence the foregoing release.

     4. Binding Effect. Except to the extent its provisions are specifically amended, modified or superseded by this Amendment, the Credit Agreement, as amended, and all terms and provisions thereof shall remain in full force and effect, and the same in all respects are confirmed and approved by the Borrower and the Lenders.

     5. First Amendment Effective Date. This Amendment shall be effective upon the satisfaction of the conditions precedent set forth in Section 6 hereof (the “First Amendment Effective Date”).

     6. Conditions Precedent. The obligations of Administrative Agent and the Lenders under this Amendment shall be subject to the following conditions precedent:

     (a) Execution and Delivery. Borrower and each Guarantor shall have executed and delivered this Amendment to Administrative Agent;

FIRST AMENDMENT TO THIRD AMENDED
AND RESTATED CREDIT AGREEMENT

     (b) Representations and Warranties. The representations and warranties of the Credit Parties under this Amendment are true and correct in all material respects as of such date, as if then made (except to the extent that such representations and warranties related solely to an earlier date);

     (c) No Default. No Default shall have occurred and be continuing;

     (d) Other Documents. The Administrative Agent shall have received such other instruments and documents incidental and appropriate to the transaction provided for herein as the Administrative Agent or its counsel may reasonably request, and all such documents shall be in form and substance satisfactory to the Administrative Agent.

     7. Representations and Warranties. Each Credit Party hereby represents and warrants that (a) except to the extent that any such representations and warranties expressly relate to an earlier date, all of the representations and warranties contained in the Credit Agreement and in each Loan Document are true and correct as of the date hereof after giving effect to this Amendment, (b) the execution, delivery and performance by such Credit Party of this Amendment have been duly authorized by all necessary corporate, limited liability company or partnership action required on its part, and this Amendment and the Credit Agreement are the legal, valid and binding obligations of such Credit Party, enforceable against such Credit Party in accordance with their terms, except as their enforceability may be affected by the effect of bankruptcy, insolvency, reorganization, moratorium or other similar laws now or hereafter in effect relating to or affecting the rights or remedies of creditors generally, and (c) no Default or Event of Default has occurred and is continuing.

     8. Counterparts. This Amendment may be executed in one or more counterparts and by different parties hereto in separate counterparts each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument; signature pages may be detached from multiple separate counterparts and attached to a single counterpart so that all signature pages are physically attached to the same document. However, this Amendment shall bind no party until the Borrower, the Lenders, and the Administrative Agent have executed a counterpart. Delivery of photocopies of the signature pages to this Amendment by facsimile or electronic mail shall be effective as delivery of manually executed counterparts of this Amendment.

     9. WRITTEN CREDIT AGREEMENT. THE CREDIT AGREEMENT, AS AMENDED BY THIS AMENDMENT AND TOGETHER WITH THE OTHER LOAN DOCUMENTS, REPRESENTS THE FINAL AGREEMENT BETWEEN AND AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN AND AMONG THE PARTIES.

     10. Guarantors. The Guarantors hereby consent to the execution of this Amendment by the Borrower and reaffirm their guaranties of all of the obligations of the Borrower to the Lenders. Borrower and Guarantors acknowledge and agree that the renewal, extension and

FIRST AMENDMENT TO THIRD AMENDED
AND RESTATED CREDIT AGREEMENT

amendment of the Credit Agreement shall not be considered a novation of account or new contract but that all existing rights, titles, powers, and estates in favor of the Lenders constitute valid and existing obligations in favor of the Lenders. Borrower and Guarantors each confirm and agree that (a) neither the execution of this Amendment or any other Loan Document nor the consummation of the transactions described herein and therein shall in any way effect, impair or limit the covenants, liabilities, obligations and duties of the Borrower and the Guarantors under the Loan Documents, and (b) the obligations evidenced and secured by the Loan Documents continue in full force and effect. Each Guarantor hereby further confirms that it unconditionally guarantees to the extent set forth in the Credit Agreement the due and punctual payment and performance of any and all amounts and obligations owed to the Lenders under the Credit Agreement or the other Loan Documents.

[Remainder of page blank. Signature pages follow]

FIRST AMENDMENT TO THIRD AMENDED
AND RESTATED CREDIT AGREEMENT

     IN WITNESS WHEREOF, the parties have caused this Amendment to the Credit Agreement to be duly executed as of the date first above written.

		BORROWER :
		RANGE RESOURCES CORPORATION
		By:
				Roger S. Manny, Senior Vice President
		GUARANTORS:
		RANGE ENERGY I, INC.
		RANGE HOLDCO, INC.
		RANGE PRODUCTION COMPANY
		RANGE ENERGY VENTURES CORPORATION GULFSTAR ENERGY, INC.
		RANGE ENERGY FINANCE CORPORATION
		PMOG HOLDINGS, INC.
		PINE MOUNTAIN ACQUISITION, INC.
		PINE MOUNTAIN OIL AND GAS, INC.
		RANGE OPERATING NEW MEXICO, INC.
		RANGE OPERATING TEXAS, LLC
		STROUD ENERGY GP, LLC
		STROUD ENERGY MANAGEMENT GP, LLC
		By:
				Roger S. Manny, Senior Vice President of all of the foregoing Credit Parties

FIRST AMENDMENT TO THIRD AMENDED
AND RESTATED CREDIT AGREEMENT
		Signature Page

		GREAT LAKES ENERGY PARTNERS, L.L.C
		By:		RANGE HOLDCO, INC., Its member
				RANGE ENERGY I, INC., Its member
		By:
				Roger S. Manny, Senior Vice President of each of the foregoing members
		RANGE PRODUCTION I, L.P.,
		By:		RANGE PRODUCTION COMPANY, Its general partner
		By:
				Roger S. Manny, Senior Vice President
		RANGE RESOURCES, L.L.C.
		By:		RANGE PRODUCTION COMPANY, Its member
				RANGE HOLDCO, INC., Its member
		By:
				Roger S. Manny, Senior Vice President of each of the foregoing members
		STROUD ENERGY LP, LLC,
		By:
				Thomas M. Strauss, Manager