Range Resources 10Q 2007 Q2 Quarterly report

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 June 30, 2007


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.)

100 Throckmorton Street, Suite 1200, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

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

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

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

Yes þ No o

Indicate by check mark whether the registrant 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

148,493,311 Common Shares were outstanding on July 24, 2007.

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended June 30, 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.

TABLE OF CONTENTS


		Page
PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements:

	Consolidated Balance Sheets (unaudited)	3

	Consolidated Statements of Operations (unaudited)	4

	Consolidated Statements of Cash Flows (unaudited)	5

	Consolidated Statements of Comprehensive Income (Loss) (unaudited)	6

	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	26

Item 4.	Controls and Procedures	28

PART II — OTHER INFORMATION

Item 5.	Submission of Matters to a Vote of Security Holders	28

Item 6.	Exhibits	29
Certification of President and CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of President and CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

PART I — Financial Information

ITEM 1. — Financial Statements

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


	June 30,			December 31,
	2007			2006

Assets
Current assets:
Cash and equivalents	$	16,594		$	2,382
Accounts receivable, less allowance for doubtful accounts of $525 and $746		144,973			125,421
Assets held for sale		—			79,304
Assets of discontinued operation		—			78,161
Unrealized derivative gain		65,285			93,588
Inventory and other		10,238			10,069

Total current assets		237,090			388,925


Unrealized derivative gain		8,425			61,068
Equity method investments		109,992			13,618

Oil and gas properties, successful efforts method		4,066,608			3,359,093
Accumulated depletion and depreciation		(872,158	)		(751,005	)

		3,194,450			2,608,088


Transportation and field assets		92,837			80,066
Accumulated depreciation and amortization		(37,692	)		(32,923	)

		55,145			47,143

Other assets		70,574			68,832

Total assets	$	3,675,676		$	3,187,674


Liabilities
Current liabilities:
Accounts payable	$	189,548		$	171,914
Asset retirement obligation		3,509			3,853
Accrued liabilities		37,047			30,026
Liabilities of discontinued operation		—			28,333
Accrued interest		13,317			12,938
Unrealized derivative loss		6,894			4,621

Total current liabilities		250,315			251,685


Bank debt		446,500			452,000
Subordinated notes		596,967			596,782
Deferred tax, net		527,036			468,643
Unrealized derivative loss		4,213			266
Deferred compensation liability		123,484			90,094
Asset retirement obligations		79,052			72,043
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, 148,442,220 issued at June 30, 2007 and 138,931,565 issued at December 31, 2006		1,484			1,389
Additional paid-in capital		1,382,726			1,079,994
Retained earnings		289,021			160,313
Common stock held by employee benefit trust, 2,201,160 issued at June 30, 2007 and 1,853,279 issued at December 31, 2006 — at cost		(36,361	)		(22,056	)
Accumulated other comprehensive income		11,239			36,521

Total stockholders’ equity		1,648,109			1,256,161

Total liabilities and stockholders’ equity	$	3,675,676		$	3,187,674

See accompanying notes.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Revenues
Oil and gas sales	$	221,591		$	149,358		$	438,617		$	315,913
Transportation and gathering		511			957			695			918
Mark-to-market on oil and gas derivatives		20,322			17,503			(45,789	)		28,784
Other		1,090			1,572			2,832			3,005

Total revenues		243,514			169,390			396,355			348,620


Costs and expenses
Direct operating		24,816			16,933			50,230			35,066
Production and ad valorem taxes		11,230			8,545			21,642			18,096
Exploration		11,725			7,763			23,435			16,685
General and administrative		17,838			12,514			32,516			23,844
Deferred compensation plan		9,334			(2,188	)		20,581			2,291
Interest expense		17,573			11,643			36,421			21,877
Depletion, depreciation and amortization		51,465			33,995			98,797			65,646

Total costs and expenses		143,981			89,205			283,622			183,505


Income from continuing operations before income taxes		99,533			80,185			112,733			165,115

Income tax provision
Current		(101	)		622			283			1,200
Deferred		34,449			29,676			38,896			60,826

		34,348			30,298			39,179			62,026


Income from continuing operations		65,185			49,887			73,554			103,089

Discontinued operations, net of income taxes		(979	)		1,383			63,789			3,856


Net income	$	64,206		$	51,270		$	137,343		$	106,945


Earnings per common share:
Basic — income from continuing operations	$	0.45		$	0.38		$	0.52		$	0.79
— discontinued operations		(0.01	)		0.01			0.45			0.03

— net income	$	0.44		$	0.39		$	0.97		$	0.82


Diluted — income from continuing operations	$	0.43		$	0.37		$	0.50		$	0.76
— discontinued operations		—			0.01			0.44			0.03

— net income	$	0.43		$	0.38		$	0.94		$	0.79


Dividends per common share	$	0.03		$	0.02		$	0.06		$	0.04

See accompanying notes.

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


	Six Months Ended
	June 30,
	2007			2006

Operating activities:
Net income	$	137,343		$	106,945
Adjustments to reconcile to net cash provided from operating activities:
Gain from discontinued operations		(63,789	)		(3,856	)
Gain from equity method investment		(796	)		(37	)
Deferred income tax expense		38,896			60,826
Depletion, depreciation and amortization		98,797			65,646
Unrealized derivative gains		(530	)		(2,994	)
Mark-to-market (gains)/losses on oil and gas derivatives		45,789			(28,784	)
Exploration dry hole costs		8,898			3,725
Amortization of deferred issuance costs and other		1,076			845
Non-cash compensation		32,689			11,754
Loss on sale of assets and other		119			923
Changes in working capital, net of amounts from business acquisitions:
Accounts receivable		(27,179	)		38,298
Inventory and other		260			(1,862	)
Accounts payable		(8,484	)		(5,516	)
Accrued liabilities and other		3,385			(5,148	)

Net cash provided from continuing operations		266,474			240,765
Net cash provided from discontinued operations		10,189			16,814

Net cash provided from operating activities		276,663			257,579


Investing activities:
Additions to oil and gas properties		(375,360	)		(188,323	)
Additions to field service assets		(13,899	)		(6,356	)
Acquisitions, net of cash acquired		(282,054	)		(308,516	)
Investing activities of discontinued operations		(7,374	)		(6,719	)
Investment in equity method affiliate and other		(93,312	)		(20,785	)
Proceeds from disposal of discontinued operations		234,303			—
Proceeds from disposal of assets		23			10

Net cash used in investing activities		(537,673	)		(530,689	)


Financing activities:
Borrowings on credit facility		570,000			507,900
Repayments on credit facility		(575,500	)		(379,500	)
Debt issuance costs		(206	)		(3,662	)
Dividends paid		(8,635	)		(5,251	)
Issuance of common stock		289,563			5,661
Issuance of subordinated notes		—			150,000

Net cash provided from financing activities		275,222			275,148


Net increase in cash and equivalents		14,212			2,038
Cash and equivalents at beginning of period		2,382			4,750

Cash and equivalents at end of period	$	16,594		$	6,788

See accompanying notes.

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Net income	$	64,206		$	51,270		$	137,343		$	106,945
Net deferred hedge gains (losses), net of tax:
Contract settlements reclassified to income		(3,682	)		9,559			(27,200	)		20,840
Change in unrealized deferred hedging gains		16,243			15,525			798			56,759
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes		782			(1,363	)		1,120			(242	)

Comprehensive income	$	77,549		$	74,991		$	112,061		$	184,302

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 is a Delaware corporation whose common stock is 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, which includes the presentation of our Gulf of Mexico operations as discontinued operations.

During the first quarter of 2007, we sold our interests in our Austin Chalk properties we purchased as part of the Stroud acquisition. We also sold our Gulf of Mexico properties. 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 $285.1 million in the first six months of 2007 compared to $696.1 million in the first six months ended June 30, 2006. The purchases included $244.9 million and $518.5 million for proved oil and gas reserves for the six months ended June 30, 2007 and 2006, respectively, with the remainder representing acreage purchases.

In May 2007, we acquired additional interests in the Nora field of Virginia and entered into a joint development plan with Equitable Resources, Inc. As a result of this transaction, Equitable and Range equalized their interests in the Nora field, including producing wells, undrilled acreage and gathering systems. Equitable will operate the producing wells, manage the drilling operations of all future coal bed methane wells and manage the gathering system. Range will oversee the drilling of formations below the coal bed methane formations, including tight gas, shale and deeper formations. A newly formed entity will hold the investment in the gathering system which is owned 50% by Equitable and 50% by Range. This investment will be accounted for as an equity method investment. Including transaction costs, we paid $278.6 million. No pro forma information has been provided as the acquisition was not considered significant.

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 to assets acquired and liabilities assumed at closing in the Stroud acquisition (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 additional information on discontinued operations. The pro forma data are based on historical information and do 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		Six Months Ended
	June 30, 2006		June 30, 2006
Revenues	$	186,122	$	383,295
Income from continuing operations		48,914		102,512
Net income		51,694		110,241

Per share data:
Income from continuing operations — basic	$	0.36	$	0.75
Income from continuing operations — diluted		0.35		0.73

Net income — basic	$	0.38	$	0.81
Net income — diluted		0.36		0.78

In February 2007, we sold the Stroud 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. In March 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. 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. These Austin Chalk properties were classified as Assets Held for Sale on our balance sheet as of December 31, 2006 and were reflected in discontinued operations in our consolidated statement of operations in the twelve months ended December 31, 2006. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. All prior year periods include the reclassification of our Gulf of Mexico operations to discontinued operations. Discontinued operations for the three month and six month periods ended June 30, 2007 and 2006 are summarized as follows (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007		2006

Revenues:
Oil and gas sales	$	(1,096	)	$	9,280		$	15,187	$	19,063
Transportation and gathering		(58	)		(59	)		10		57
Other		—			—			310		—
Gain (loss) on disposition of assets and other		(406	)		—			93,055		(1	)

		(1,560	)		9,221			108,562		19,119


Costs and expenses:
Direct operating		(198	)		3,661			2,559		5,190
Production and ad valorem taxes		—			192			141		368
Exploration and other		146			15			212		1,170
Interest expense		—			360			845		677
Depletion, depreciation and amortization		—			2,838			6,672		5,754

		(52	)		7,066			10,429		13,159


Income (loss) from discontinued operations before income taxes		(1,508	)		2,155			98,133		5,960

Income tax expense (benefit)		(529	)		772			34,344		2,104


Income (loss) from discontinued operations, net of taxes	$	(979	)	$	1,383		$	63,789	$	3,856


Production:
Crude oil (bbls)		—			31,008			40,634		57,192
Natural gas (mcf)		—			1,296,261			1,990,277		2,452,662
Total (mcfe)		—			1,482,309			2,234,081		2,795,814

(5) INCOME TAXES

Income taxes included in continuing operations were as follows (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Income tax expense	$	34,348		$	30,298		$	39,179		$	62,026
Effective tax rate		34.5	%		37.8	%		34.8	%		37.6	%

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 unusual or extraordinary transactions. Income taxes for unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. For the three months and six months ended June 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due to state income taxes and an increase in our deferred tax assets related to state tax credit carryforwards. For the three months and six months ended June 30, 2006, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due to state income taxes. We expect our effective tax rate to be approximately 37% for the remainder of 2007.

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. Even with the gain recognized on the sale of our Gulf of Mexico assets, we expect our NOL carryovers to increase in 2007. Our deferred tax asset related to regular NOL carryovers at December 31, 2006 was $80.3 million. At December 31, 2006, we had AMT credit carryovers of $700,000 that are not subject to limitation or expiration.

(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						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006

Numerator:
Income from continuing operations	$	65,185		$	49,887		$	73,554		$	103,089
Income (loss) from discontinued operations, net of taxes		(979	)		1,383			63,789			3,856

Net income	$	64,206		$	51,270			137,343		$	106,945


Denominator:
Weighted average shares outstanding		146,214			132,156			142,733			131,453
Stock held in the deferred compensation plan and restricted stock		(1,045	)		(1,403	)		(1,089	)		(1,413	)

Weighted average shares, basic		145,169			130,753			141,644			130,040


Effect of dilutive securities:
Weighted average shares outstanding		146,214			132,156			142,733			131,453
Employee stock options, SARs and other		3,968			3,802			3,883			3,827
Treasury shares		—			—			—			(2	)

Dilutive potential common shares for diluted earnings per share		150,182			135,958			146,616			135,278


Earnings per common share basic and diluted:
Basic — income from continuing operations	$	0.45		$	0.38		$	0.52		$	0.79
— discontinued operations		(0.01	)		0.01			0.45			0.03

— net income	$	0.44		$	0.39		$	0.97		$	0.82


Diluted — income from continuing operations	$	0.43		$	0.37		$	0.50		$	0.76
— discontinued operations		—			0.01			0.44			0.03

— net income	$	0.43		$	0.38		$	0.94		$	0.79

Stock appreciation rights for 271,000 and 140,000 shares were outstanding but not included in the computations of diluted net income per share for the three months and the six months ended June 30, 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. Stock appreciation rights for 18,000 shares were outstanding but not included in the computations of diluted net income per share for the three months and the six months ended June 30, 2006 because the exercise price of the SARs was greater than the average 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 six months ended June 30, 2007 and the year ended December 31, 2006 (in thousands):


	June 30,			December 31,
	2007			2006

Beginning balance at January 1	$	9,984		$	25,340
Additions to capitalized exploratory well costs pending the determination of proved reserves		19,312			4,695
Reclassifications to wells, facilities and equipment based on determination of proved reserves		—			(16,710	)
Capitalized exploratory well costs charged to expense		(8,018	)		(3,341	)
Divested wells		(1,325	)		—
Balance at end of period		19,953			9,984
Less exploratory well costs that have been capitalized for a period of one year or less		(19,953	)		(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 $20.0 million of capitalized exploratory well costs at June 30, 2007 was incurred in 2007 ($16.8 million) and in 2006 ($3.2 million).

(8) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at June 30, 2007 is shown parenthetically). No interest expense was capitalized during the three month or the six month periods ended June 30, 2007 and 2006.


	June 30,		December 31,
	2007		2006

Bank debt (6.4%)	$	446,500	$	452,000

Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount		197,429		197,262
6.375% Senior Subordinated Notes due 2015		150,000		150,000
7.5% Senior Subordinated Notes due 2016, net of discount		249,538		249,520

Total debt	$	1,043,467	$	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. In March 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 June 30, 2007, the outstanding balance under the bank credit facility was $446.5 million and there was $453.5 million of borrowing capacity available. The credit facility 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 6.5% for the three months ended June 30, 2007 compared to 6.3% for the three months ended June 30, 2006. The weighted average interest rate on the bank credit facility was 6.5% for the six months ended June 30, 2007 compared to 5.9% for the same period of 2006. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At June 30, 2007, the commitment fee was 0.25% and the interest rate margin was 1.0%. At July 24, 2007, the interest rate (including applicable margin) was 6.5%.

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 is 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 June 30, 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 $699.3 million was available under the bank credit facility’s restricted payment basket on June 30, 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 June 30, 2007, $870.0 million was available under the restricted payment baskets for each of the 7.375% Notes and the 6.375% Notes and there was $951.0 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 six months ended June 30, 2007 and 2006 is as follows (in thousands):


	Six Months Ended
	June 30,
	2007			2006

Beginning of period	$	95,589		$	68,063
Liabilities incurred		5,260			2,909
Liabilities settled		(374	)		(2,064	)
Disposition of wells		(20,849	)		1,403
Accretion expense — continuing operations		2,553			1,504
Accretion expense — discontinued operations		382			716
Change in estimate		—			2,538

End of period	$	82,561		$	75,069

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:


	Six Months Ended		Year Ended
	June 30, 2007		December 31, 2006

Beginning balance		138,931,565		129,907,220

Equity offering		8,050,000		—
Shares issued for Stroud acquisition		—		6,517,498
Stock options/SARs exercised		1,023,105		1,956,164
Restricted stock grants		394,497		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

		9,510,655		9,024,345


Ending balance		148,442,220		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 June 30, 2007, we had open swap contracts covering 57.8 Bcf of gas at prices averaging $9.30 per mcf. We also had collars covering 38.3 Bcf of gas at weighted average floor and cap prices which range from $7.43 to $10.57 per mcf and 7.4 million barrels of oil at weighted average floor and cap prices that range from $60.27 to $74.09 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 June 30, 2007, was a net unrealized pre-tax gain of $62.6 million. These contracts expire monthly through December 2009. Settled transaction gains and losses 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 realized gains of $5.8 million in the second quarter of 2007 compared to realized losses of $13.6 million in the second quarter of 2006. Oil and gas revenues were increased by realized gains of $41.4 million in the first six months of 2007 compared with realized losses of $30.7 million in the six months ended June 30, 2006. Other revenues in our consolidated statement of operations include ineffective hedging gains on hedges that qualified for hedge accounting of $530,000 in the first six months of 2007 compared with gains of $3.3 million in the first six months of 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting and are marked to market. As a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf Coast production is now being marked to market. This situation where we are marking the derivative instrument to market resulted in a loss of $45.8 million in the first six months of 2007 compared to a gain of $28.8 million in the first six months of 2006.

The following table sets forth our derivative volumes by year as of June 30, 2007:


Period	Contract Type	Volume Hedged	Average Hedge Price

Natural Gas
2007	Swaps	105,000 Mmbtu/day		$9.04
2007	Collars	98,500 Mmbtu/day		$6.87 — $9.66
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	9,000 bbl/day		$59.34 — $75.48
2009	Collars	8,000 bbl/day		$64.01 — $76.00

The combined fair values of net unrealized gains on oil and gas derivatives totaled $62.6 million and appear as unrealized derivative gains and losses on the balance sheet as of June 30, 2007. 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		1,642,692			33.65
Exercised		(1,189,940	)		11.96
Expired/forfeited		(237,806	)		22.87

Outstanding on June 30, 2007		9,067,072		$	16.39

The following table shows information with respect to outstanding stock options and SARs at June 30, 2007:


	Outstanding						Exercisable
			Weighted- Average
			Remaining		Weighted-Average				Weighted- Average
Range of Exercise Prices	Shares		Contractual Life		Exercise Price		Shares		Exercise Price

$ 1.29 — $ 4.99		2,315,416		2.52	$	3.62		2,315,416	$	3.62
5.00 — 9.99		1,038,813		1.64		7.01		1,038,813		7.01
10.00 — 14.99		336,468		2.36		11.57		165,827		12.39
15.00 — 19.99		2,248,567		2.99		16.85		1,217,066		16.94
20.00 — 24.99		1,397,641		3.75		24.22		428,083		24.22
25.00 — 29.99		145,500		3.77		26.44		26,550		26.15
30.00 — 34.99		1,030,500		4.64		31.44		—		—
35.00 — 39.99		551,767		4.90		37.99		44,100		38.02
40.00 — 41.01		2,400		4.93		41.01		—		—

Total		9,067,072		3.13	$	16.39		5,235,855	$	9.76

The weighted average fair value of an SAR to purchase one share of common stock granted during 2007 was $10.63. The fair value of each stock 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 4.74%; dividend yield of 0.36%; expected volatility of 36%; and an expected life of 3.54 years.

As of June 30, 2007, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $190.9 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $144.8 million and 2.63 years, respectively. As of June 30, 2007, the number of fully-vested awards and awards expected to vest was 8.8 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $16.06 and 3.10 years, respectively, and the aggregate intrinsic value was $188.8 million. As of June 30, 2007, unrecognized compensation cost related to the awards was $24.8 million, which is expected to be recognized over a weighted average period of 1.27 years. At June 30, 2006, 4.8 million options are outstanding with a weighted-average exercise price of $7.81 and 4.2 million SARs are outstanding with a weighted average grant price of $26.21.

Restricted Stock Grants

During the first six months of 2007, 423,000 shares of restricted stock were issued to employees at an average price of $34.72 and have a three-year vesting period. In the first six months of 2006, we issued 421,000 shares of restricted stock as compensation to directors and employees at an average price of $24.34. 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 $2.9 million in the second quarter of 2007 compared to $1.1 million in the same quarter of the prior year. We recorded compensation expense related to restricted stock grants of $4.2 million in the first six months of 2007 compared to $1.5 million in the six month period ended June 30, 2006. As of June 30, 2007, unrecognized compensation cost related to these restricted stock awards was $22.9 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 $9.3 million in the second quarter of 2007 compared to income of $2.1 million in the second quarter of 2006. We recorded non-cash mark-to-market expense related to our deferred compensation plan of $20.6 million in the first six months of 2007 compared to $2.3 million in the six months ended June 30, 2006.

(13) SUPPLEMENTAL CASH FLOW INFORMATION


	Six Months Ended
	June 30,
	2007		2006
	(in thousands)

Non-cash investing and financing activities included:
Common stock issued under compensation arrangements	$	1,938	$	916
Asset retirement costs capitalized		2,145		5,709
Shares issued for Stroud purchase		—		177,679
Stock options assumed in Stroud acquisition		—		9,478

Net cash provided from operating activities included:
Income taxes paid (refunded)	$	44	$	(673	)
Interest paid		35,776		19,999

(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)


	June 30,			December 31,
	2007			2006
	(in thousands)
Oil and gas properties:
Properties subject to depletion	$	3,817,906		$	3,132,830
Unproved properties		248,702			226,263

Total		4,066,608			3,359,093
Accumulated depreciation, depletion and amortization		(872,158	)		(751,005	)

Net capitalized costs	$	3,194,450		$	2,608,088


^(a)		Includes capitalized asset retirement costs and associated accumulated amortization.

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


	Six Months Ended		Year Ended
	June 30, 2007		December 31, 2006
	(in thousands)
Acquisitions:
Acreage purchases	$	32,744	$	79,762
Unproved leasehold		4,379		132,821
Proved oil and gas properties		244,912		209,262
Purchase price adjustment^(b)		—		147,062
Asset retirement obligations		3,091		896

Development		368,562		464,586

Exploration^(c)		48,609		70,870

Gas gathering facilities		8,138		19,690

Subtotal		710,435		1,124,949

Asset retirement obligations		2,145		25,821

Total costs incurred^(d)	$	712,580	$	1,150,770


^(a)		Includes costs incurred whether capitalized or expensed.

		^(b) Represents non-cash gross up to account for difference in book and tax basis.

^(c)		Includes $23,435 of exploration costs expensed in the six months ended June 30, 2007 and $45,252 of exploration costs expensed in the year ended December 31, 2006. Exploration expense includes $1.7 million of stock-based compensation in the six months ended June 30, 2007 and $3.1 million of stock-based compensation in the year ended December 31, 2006.

^(d)		In 2006, $21.5 million is related to our divested Gulf of Mexico properties.

(17) NEW ACCOUNTING STANDARD

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). 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 U.S. 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 June 30, 2007.

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				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Production:
Crude oil (bbls)		881,641		752,484		1,720,129		1,495,995
NGLs (bbls)		280,407		287,600		553,537		554,653
Natural gas (mcf)		21,514,007		16,504,525		41,208,030		32,268,230
Total (mcfe)^(a)		28,486,295		22,745,029		54,850,026		44,572,118

Average daily production:
Crude oil (bbls)		9,688		8,269		9,503		8,265
NGLs (bbls)		3,081		3,160		3,058		3,064
Natural gas (mcf)		236,418		181,368		227,669		178,278
Total (mcfe)^(a)		313,036		249,945		303,039		246,255

Average sales prices (excluding hedging):
Crude oil (per bbl)	$	62.20	$	65.36	$	59.18	$	62.57
NGLs (per bbl)	$	40.31	$	35.19	$	35.29	$	32.58
Natural gas (per mcf)	$	6.96	$	6.28	$	6.70	$	7.28
Total (per mcfe)^(a)	$	7.57	$	7.17	$	7.25	$	7.78

Average sales prices (including hedging):
Crude oil (per bbl)	$	60.01	$	47.52	$	58.05	$	47.03
NGLs (per bbl)	$	40.31	$	35.19	$	35.29	$	32.58
Natural gas (per mcf)	$	7.32	$	6.27	$	7.75	$	7.05
Total (per mcfe)^(a)	$	7.78	$	6.57	$	8.00	$	7.09

Average NYMEX prices^(b)
Oil (per bbl)	$	65.03	$	70.70	$	61.65	$	67.09
Natural gas (per mcf)	$	7.56	$	6.82	$	7.26	$	7.95


^(a)		Oil and NGLs are converted at the rate of one barrel equals six mcfe.

^(b)		Based on average of bid week prompt month prices.

Overview

Revenues increased 44% for the second quarter of 2007 over the same period of 2006. This increase is due to higher production, realized prices and a favorable mark-to-market value adjustment on oil and gas derivatives that do not qualify for hedge accounting. For the second quarter of 2007, production increased 25% due to the continued success of our drilling program and our acquisitions. Realized oil and gas prices were 18% higher in the second quarter of 2007 compared to the same period of 2006. Our hedges increased revenue by $5.8 million in the second quarter of 2007 compared to a decrease of $13.7 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 continued 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, an 18% increase from the second quarter of 2006 to the second quarter of 2007. It is anticipated that service and personnel costs will remain high as oil and gas industry fundamentals remain favorable.

In the first quarter of 2007, we sold our Austin Chalk properties that were purchased as part of our Stroud acquisition and our Gulf of Mexico assets. These operations are shown in discontinued operations for all periods presented.

Comparison of Quarter Ended June 30, 2007 and 2006

Oil and gas revenuefor the three months ended June 30, 2007 and 2006 (in thousands) is summarized in the following table:


				Three Months Ended June 30,
	2007			2006			Change		%
Oil and Gas Revenues:

Oil wellhead	$	54,840		$	49,184		$	5,656		11	%
Oil hedges realized		(1,932	)		(13,425	)		11,493		86	%

Total oil revenue	$	52,908		$	35,759		$	17,149		48	%


Gas wellhead	$	149,602		$	103,713		$	45,889		44	%
Gas hedges realized		7,778			(234	)		8,012		3,424	%

Total gas revenue	$	157,380		$	103,479		$	53,901		52	%


NGL revenue	$	11,303		$	10,120		$	1,183		12	%


Combined wellhead	$	215,745		$	163,017		$	52,728		32	%
Combined hedges		5,846			(13,659	)		19,505		143	%

Total oil and gas revenue	$	221,591		$	149,358		$	72,233		48	%

Average realized pricesreceived for oil and gas during the second quarter of 2007 was $7.78 per mcfe, up 18% or $1.21 per mcfe from the same quarter of the prior year. The average price received in the second quarter for oil increased 26% to $60.01 per barrel and increased 17% to $7.32 per mcf for gas from the same period of 2006. Our hedging program increased realized prices $0.21 per mcfe in the second quarter of 2007 versus a decrease of $0.60 per mcfe in the same period of 2006.

Production volumesincreased 25% from the second quarter of 2006 primarily due to continued drilling success and our acquisitions. Our production for the second quarter was 313.0 Mmcfe per day of which 61% was attributable to our Southwestern division, 37% to our Appalachian division and 2% to our Gulf Coast division.

Mark-to-market on oil and gas derivativesincludes a gain of $20.3 million in 2007 compared to a gain of $17.5 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. In addition, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf of Mexico production is now being marked to market. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from ineffective hedges are included in revenues and are not included in other comprehensive income. As commodity prices increase or decrease, such changes will have an opposite effect on the

mark-to-market. Because gas prices decreased in the second quarter, our hedges became comparatively more valuable. However, we expect these gains will be offset by lower revenues in the future.

Transportation and gathering revenueof $510,000 decreased $447,000 from 2006. This decrease is primarily due to lower processing margins and lower transmission revenues.

Other revenuedecreased in 2007 to $1.1 million from $1.6 million in 2006. The 2007 period includes $749,000 of ineffective hedging gains and income from equity method investments of $385,000. Other revenue for 2006 includes $1.9 million of ineffective hedging gains partially offset by a $453,000 loss on asset retirement obligation settlements.

Our operating expenses have increased as we continue to grow. We believe 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 June 30, 2007 and 2006:


Operating expenses per mcfe	2007		2006		Change		%

Direct operating expense (excluding $0.02 per mcfe stock-based compensation in 2007 and $0.02 per mcfe in 2006)	$	0.85	$	0.73	$	0.12		16	%
Production and ad valorem tax expense		0.39		0.38		0.01		3	%
General and administrative expense (excluding stock-based compensation of $0.19 per mcfe in 2007 and $0.18 per mcfe in 2006)		0.44		0.37		0.07		19	%
Interest expense		0.62		0.51		0.11		22	%
Depletion, depreciation and amortization expense		1.81		1.49		0.32		21	%

Direct operating expense(excluding stock-based compensation) increased $7.8 million in the second quarter of 2007 to $24.3 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 ($0.07 per mcfe) of workover costs in 2007 versus $747,000 ($0.03 per mcfe) in 2006. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) increased $0.12 from the same period of 2006 with the increase consisting primarily of higher water disposal costs ($0.04 per mcfe), higher well service costs ($0.03 per mcfe) and higher workover costs ($0.03 per mcfe).

Production and ad valorem taxesare paid based on market prices, not hedged prices. These taxes increased $2.7 million or 31% 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 $0.39 in 2007 from $0.38 in the same period of 2006.

General and administrative expense(excluding stock-based compensation) for the second quarter of 2007 increased $4.0 million to $12.5 million from 2006 due to higher salaries and benefits ($2.8 million), higher office rent and general office expense ($526,000) and higher professional and accounting fees ($675,000). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.37 in the second quarter of 2006 to $0.44 in the second quarter of 2007.

Interest expensefor the second quarter of 2007 increased $5.9 million to $17.6 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 $3.5 million of interest costs in the second 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 second quarter of 2007 was $357.7 million compared to $264.6 million for the second quarter of 2006 and the average interest rates were 6.5% in the second quarter of 2007 compared to 6.3% in the same quarter of the prior year.

Depletion, depreciation and amortization(“DD&A”) increased $17.5 million or 51% to $51.5 million in the second quarter of 2007 with a 25% increase in production and a 22% 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 $1.49 in the second quarter of 2006 to $1.81 in the second quarter of 2007.

million. In 2006, stock-based compensation is a component of direct operating expense ($366,000), exploration expense ($830,000), general and administrative expense ($4.1 million) and an $86,000 reduction of net gas transportation revenues for a total of $5.4 million.

Exploration expensefor the second quarter of 2007 increased $4.0 million to $11.7 million due to higher dry hole and personnel costs. The following table details our exploration-related expenses for the three months ended June 30, 2007 and 2006 (in thousands):


Exploration expenses	2007		2006		Change		%

Dry hole expense	$	4,490	$	2,029	$	2,461		121	%
Seismic		2,860		2,491		369		15	%
Personnel expense		2,330		1,615		715		44	%
Stock-based compensation expense		920		830		90		11	%
Other		1,125		798		327		41	%

Total exploration expense	$	11,725	$	7,763	$	3,962		51	%

Deferred compensation plan expensefor the second quarter of 2007 increased $11.5 million to $9.3 million from 2006 due to an increase in our stock price. Our stock price increased from $33.40 at March 31, 2007 to $37.41 at June 30, 2007. This non-cash category reflects increases or decreases in value of our common stock and other investments held in our non-qualified deferred compensation plans.

Incometax expensefor 2007 increased to $34.3 million reflecting a 24% increase in income from continuing operations before taxes compared to the same period of 2006. The second quarter of 2007 provides for a tax expense at an effective rate of approximately 35% compared to 38% in the same period of 2006. In the second quarter of 2007, we recognized a non-recurring $3.0 million tax benefit related to an increase in the Texas margin tax credit carryforward. Current income tax benefit of $101,000 represent primarily state income taxes. See also Note 5 to our consolidated financial statements.

Discontinued operationsinclude the operating results related to our Gulf of Mexico properties and Austin Chalk properties that we sold in the first quarter of 2007. The second quarter of 2007 and 2006 provide for a tax expense at an effective rate of approximately 35%. See also Note 4 to our consolidated financial statements.

Comparison of Six Months Ended June 30, 2007 and 2006

Oil and gas revenuefor the six months ended June 30, 2007 and 2006 (in thousands) is summarized in the following table:


	Six Months Ended June 30,
	2007			2006			Change		%
Oil and Gas Revenues:

Oil wellhead	$	101,801		$	93,602		$	8,199		9	%
Oil hedges realized		(1,944	)		(23,244	)		21,300		92	%

Total oil revenue	$	99,857		$	70,358		$	29,499		42	%


Gas wellhead	$	275,926		$	234,954		$	40,972		17	%
Gas hedges realized		43,301			(7,469	)		50,770		680	%

Total gas revenue	$	319,227		$	227,485		$	91,742		40	%


NGL revenue	$	19,533		$	18,070		$	1,463		8	%


Combined wellhead	$	397,260		$	346,626		$	50,634		15	%
Combined hedges		41,357			(30,713	)		72,070		235	%

Total oil and gas revenue	$	438,617		$	315,913		$	122,704		39	%

Average realized pricesreceived for oil and gas during the first six months of 2007 was $8.00 per mcfe, up 13% or $0.91 per mcfe from the same period of the prior year. The average price received in the first six months for oil increased

23% to $58.05 per barrel and increased 10% to $7.75 per mcf for gas from the same period of 2006. The effect of our hedging program increased realized prices $0.75 per mcfe in the first six months of 2007 versus a decrease of $0.69 per mcfe in the same period of 2006.

Production volumesincreased 23% from the first six months of 2006 primarily due to continued drilling success and our acquisitions. Our production for the first six months was 303.0 Mmcfe per day of which 61% was attributable to our Southwestern division, 37% to our Appalachian division and 2% to our Gulf Coast division.

Mark-to-market on oil and gas derivativesincludes a loss of $45.8 million in 2007 compared to a gain of $28.8 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. In addition, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007, a portion of the derivatives which were designated to our Gulf of Mexico production is now being marked-to-market. 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 six months, our hedges became comparatively less valuable. However, we expect these losses will be offset by higher revenues in the future.

Other revenuedecreased in 2007 to $2.8 million from $3.0 million in 2006. The 2007 period includes insurance proceeds of $1.0 million, income from equity method investments of $796,000 and $530,000 of ineffective hedging gains. Other revenue for 2006 includes $3.3 million of ineffective hedging gains.

Our operating expenses have increased as we continue to grow. We believe 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 a mcfe basis for the first six months ended June 30, 2007 and 2006:


Operating expenses per mcfe	2007		2006		Change			%

Direct operating expense (excluding $0.02 per mcfe stock-based compensation in 2007 and $0.01 per mcfe in 2006)	$	0.90	$	0.77	$	0.13			17	%
Production and ad valorem tax expense		0.39		0.41		(0.02	)		5	%
General and administrative expense (excluding stock-based compensation of $0.16 per mcfe in 2007 and $0.14 per mcfe in 2006)		0.43		0.39		0.04			10	%
Interest expense		0.66		0.49		0.17			35	%
Depletion, depreciation and amortization expense		1.80		1.47		0.33			22	%

Direct operating expense(excluding stock-based compensation) increased $14.9 million in the first six months of 2007 to $49.4 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 $3.2 million ($0.06 per mcfe) of workover costs in 2007 versus $1.4 million ($0.03 per mcfe) in 2006. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) increased $0.13 from the same period of 2006 with the increase consisting primarily of higher water disposal costs ($0.04 per mcfe), higher well service costs ($0.04 per mcfe) and higher workover costs ($0.04 per mcfe).

Production and ad valorem taxesare paid based on market prices, not hedged prices. These taxes increased $3.5 million or 20% 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 in 2007 from $0.41 in the same period of 2006.

General and administrative expense(excluding stock-based compensation) for the first six months of 2007 increased $6.1 million to $23.5 million from 2006 due to higher salaries and benefits ($3.9 million), higher office rent and general office expense ($785,000) and higher professional and accounting fees ($640,000). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.39 in the first six months of 2006 to $0.43 in the first six months of 2007.

Interest expensefor the first six months of 2007 increased $14.5 million to $36.4 million due to rising interest rates, higher average debt balances 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 $8.2 million of interest costs in the first six months 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 six months of 2007 was $432.5 million compared to $271.6 million for the first six months of 2006 and the average interest rates were 6.5% in the first six months of 2007 compared to 5.9% in the same period of the prior year.

Depletion, depreciation and amortization(“DD&A”) increased $33.2 million or 50% to $98.8 million in the first six months of 2007 with a 23% increase in production and a 23% 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 $1.47 in the first six months of 2006 to $1.80 in the first six months of 2007.

Operating expensesalso 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 ($868,000), exploration expense ($1.7 million), general and administrative expense ($9.0 million) and a $194,000 reduction of net gas transportation revenues for a total of $11.7 million. In 2006, stock-based compensation is a component of direct operating expense ($652,000), exploration expense ($1.4 million), general and administrative expense ($6.4 million) and a $150,000 reduction of net gas transportation revenues for a total of $8.7 million.

Exploration expensefor the first six months of 2007 increased $6.7 million to $23.4 million due to higher dry hole costs. The following table details our exploration-related expenses for the first six months ended June 30, 2007 and 2006 (in thousands):


Exploration expenses	2007		2006		Change			%

Dry hole expense	$	8,898	$	3,729	$	5,169			139	%
Seismic		6,336		6,943		(607	)		9	%
Personnel expense		4,327		3,164		1,163			37	%
Stock-based compensation expense		1,659		1,439		220			15	%
Other		2,215		1,410		805			57	%

Total exploration expense	$	23,435	$	16,685	$	6,750			40	%

Deferred compensation plan expensefor the first six months of 2007 increased $18.3 million from the same period of 2006 due to an increase in our stock price. Our stock price increased from $27.46 at December 31, 2006 to $37.41 at June 30, 2007. This non-cash category reflects increases or decreases in value of our common stock and other investments held in our non-qualified deferred compensation plans.

Incometax expensefor 2007 decreased to $39.2 million reflecting the 32% decrease in income from continuing operations before taxes compared to the same period of 2006. The first six months of 2007 provides for a tax expense at an effective rate of approximately 35% compared to 38% in the same period of 2006. The six months ended June 30, 2007 includes a non-recurring $3.0 million tax benefit related to an increase in the Texas Margin tax credit carryforward. Current income taxes of $283,000 represent primarily state income taxes. See also Note 5 to our consolidated financial statements.

Discontinued operationsinclude the operating results related to our Gulf of Mexico properties and Austin Chalk properties that we sold in the first quarter of 2007. The first six months of 2007 and 2006 provide for a tax expense at an effective rate of approximately 35%. See also Note 4 to our consolidated financial statements.

Liquidity and Capital Resources

During the six months ended June 30, 2007, our cash provided from continuing operations was $266.5 million and we spent $764.7 million on capital expenditures (including acquisitions and equity investments). During this period, financing activities provided net cash of $275.2 million. At June 30, 2007, we had $16.6 million in cash, total assets of $3.7 billion and a debt-to-capitalization ratio of 38.8%. Long-term debt at June 30, 2007 totaled $1.0 billion including $446.5 million of bank credit facility debt and $597.0 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at June 30, 2007 was $453.5 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 subsequently used to fund a portion of the Nora 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 June 30, 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 $699.3 million was available under the bank credit facility’s restricted payment basket on June 30, 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 $870.0 million was available under each of the 7.375% Notes and the 6.375% Notes restricted payment basket on June 30, 2007. There was $951.0 million available under the 7.5% Note restricted payment basket at June 30, 2007.

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 July 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 $396.5 million on July 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 June 30, 2007, we have entered into hedging agreements covering 44.4 Bcfe, 78.3 Bcfe and 17.5 Bcfe for 2007, 2008 and 2009, respectively. Net cash provided from continuing operations for the six months ended June 30, 2007 was $266.5 million compared to $240.8 million in the six months ended June 30, 2006. Cash flow from operations was higher than the prior year due to higher volumes and realized prices partially offset by higher operating costs. Net cash used in investing for the six months ended June 30, 2007 was $537.7 million compared to $530.7 million in the same period of 2006. The 2007 period includes $375.4 million of additions to oil and gas properties, $282.1 million of acquisitions partially offset by proceeds of $234.3 million from asset sales. The 2006 period included $188.3 million of additions to oil and gas properties and $308.5 million of acquisitions. Net cash provided from financing for the six months ended June 30, 2007 was $275.2 million compared to $275.1 million in the first six months of 2006. During the first six months of 2007 total debt decreased $5.3 million.

Dividends

On June 1, 2007, the Board of Directors declared a dividend of three cents per share ($4.4 million) on our common stock, payable on June 30, 2007 to stockholders of record at the close of business on June 15, 2007.

Capital Requirements and Contractual Cash Obligations

The 2007 capital budget is currently set at $834.0 million (excluding acquisitions) and based on current projections, is expected to be funded with internal cash flow and asset sales. For the six months ended June 30, 2007, $417.2 million of development and exploration spending was funded with internal cash flow and proceeds from the sale of assets.

There have been no significant changes to our contractual obligations subsequent to December 31, 2006. 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 June 30, 2007, swaps were in place covering 57.7 Bcf of gas at prices averaging $9.30 per mcf. We also have collars covering 38.3 Bcf of gas at weighted average floor and cap prices which range from $7.43 to $10.57 per mcf and 7.4 million barrels of oil at weighted average floor and cap prices that range from $60.27 to $74.09 per barrel. Their fair value at June 30, 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 $62.6 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 six months of 2007, this resulted in a loss of $45.8 million compared to a gain of $28.8 million in the same period of 2006.

At June 30, 2007, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Average Hedge Price

Natural Gas
2007	Swaps	105,000 Mmbtu/day	$9.04
2007	Collars	98,500 Mmbtu/day	$6.87 — $9.66
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	9,000 bbl/day	$59.34 — $75.48
2009	Collars	8,000 bbl/day	$64.01 — $76.00

Interest Rates

At June 30, 2007, we had $1.0 billion of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Bank debt totaling $446.5 million bears interest at floating rates, which average 6.4% at June 30, 2007. The 30 day LIBOR rate on June 30, 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 second quarter of 2007, we received an average of $62.20 per barrel of oil and $6.96 per mcf of gas before hedging compared to $65.36 per barrel of oil and $6.28 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 June 30, 2007, we had gas swaps in place covering 57.8 Bcf of gas. We also had collars covering 38.3 Bcf of gas and 7.4 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 $62.6 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 six months ended June 30, 2007 were $41.4 million compared to losses of $30.7 million in the first six 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 gain of $530,000 in the first six months of 2007 compared to a gain of $3.3 million in the first six 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. In addition, as a result of the sale of our Gulf of Mexico assets in the first quarter of 2007 a portion of the derivatives designated against our Gulf of Mexico production is now being marked to market. This resulted in a loss of $45.8 million in the first six months of 2007 compared to a gain of $28.8 million in the same period of 2006.

At June 30, 2007, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Average Hedge Price	Fair Market Value
				(In thousands)
Natural Gas
2007	Swaps	105,000 Mmbtu/day	$9.04	$32,423
2007	Collars	98,500 Mmbtu/day	$6.87 — $9.66	$ 4,938
2008	Swaps	105,000 Mmbtu/day	$9.42	$37,437
2008	Collars	55,000 Mmbtu/day	$7.93 — $11.40	$ 8,555

Crude Oil
2007	Collars	6,300 bbl/day	$53.46 — $65.33	$(9,163)
2008	Collars	9,000 bbl/day	$59.34 — $75.48	$(8,183)
2009	Collars	8,000 bbl/day	$64.01 — $76.00	$(3,404)

In the first six months of 2007, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $39.4 million. If oil and gas future prices at June 30, 2007 declined 10%, the unrealized hedging gain at that date would have increased by $70.6 million.

Interest rate risk.At June 30, 2007, we had $1.0 billion of debt outstanding. Of this amount, $600.0 million bore interest at fixed rates averaging 7.2%. Senior debt totaling $446.5 million bore interest at floating rates averaging 6.4%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $4.5 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 5. Submission of Matters to a Vote of Security Holders

On May 23, 2007, we held our annual meeting of stockholders to elect a Board of eight directors, each for a one-year term, vote on proposals to increase the number of common stock authorized to be issued under the 2005 Equity Based Compensation Plan and appoint Ernst & Young LLP as our independent auditors for 2007. At the meeting, Charles L. Blackburn, Anthony V. Dub, V. Richard Eales, Allen Finkelson, Jonathan S. Linker, Kevin S. McCarthy, John H. Pinkerton and Jeffrey L. Ventura were re-elected as Directors. Charles L. Blackburn remains the non-executive Chairman of the Board.

The following is a summary of the votes cast at the annual meeting:


Results of Voting			Votes For		Withheld
	1.	Election of Directors
		Charles L. Blackburn		123,707,077		981,858
		Anthony V. Dub		122,774,851		1,910,084
		V. Richard Eales		124,389,326		295,609
		Allen Finkelson		122,058,249		2,626,686
		Jonathan S. Linker		124,366,657		318,278
		Kevin S. McCarthy		123,678,684		1,006,252
		John H. Pinkerton		122,762,526		1,922,409
		Jeffrey L. Ventura		122,753,426		1,931,510


		Votes For		Against		Abstentions		Broker Non-Votes
2.	Increase authorized shares under the Plan		65,026,274		50,685,795		83,143		8,889,723
3.	Appointment of Ernst & Young LLP		124,498,948		143,475		42,512		—

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)

	10.3	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


*		filed herewith

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.


	RANGE RESOURCES CORPORATION
	By:	/s/ ROGER S. MANNY
		Roger S. Manny
		Senior Vice President and Chief Financial Officer (Principal Financial Officer and duly authorized to sign this report on behalf of the Registrant)

July 25, 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)

	10.3	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


*		filed herewith

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

Range Resources (RRC) 10-Q2007 Q2 Quarterly report

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