Edgar Filing: RANGE RESOURCES CORP

e10vq

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, 2008


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 (State or Other Jurisdiction of Incorporation or Organization)		34-1312571 (IRS Employer Identification No.)

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

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

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

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

Yes þ No o

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

Large accelerated filer þ

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company 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

155,102,043 Common Shares were outstanding on July 21, 2008.

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended June 30, 2008

Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees.

TABLE OF CONTENTS


			Page
PART I — FINANCIAL INFORMATION
	Item 1.	Financial Statements:
		Consolidated Balance Sheets (unaudited)		3

		Consolidated Statements of Operations (unaudited)		4

		Consolidated Statements of Cash Flows (unaudited)		5

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

		Selected Notes to Consolidated Financial Statements (unaudited)		7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

	Item 3.	Quantitative and Qualitative Disclosures about Market Risk		29

	Item 4.	Controls and Procedures		30

PART II — OTHER INFORMATION

	Item 4.	Submission of Matters to a Vote of Security Holders		30

	Item 6.	Exhibits		31

PART I — Financial Information
Item 1. — Financial Statements

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


	June 30,			December 31,
	2008			2007
	(Unaudited)
Assets
Current assets:
Cash and equivalents	$	73		$	4,018
Accounts receivable, less allowance for doubtful accounts of $451 and $583		253,512			166,484
Unrealized derivative gain		1,603			53,018
Deferred tax asset		142,552			26,907
Inventory and other		40,371			11,387

Total current assets		438,111			261,814


Unrealized derivative gain		3,218			1,082
Equity method investments		127,812			113,722

Oil and gas properties, successful efforts method		5,205,547			4,443,577
Accumulated depletion and depreciation		(1,043,099	)		(939,769	)

		4,162,448			3,503,808


Transportation and field assets		120,706			104,802
Accumulated depreciation and amortization		(49,443	)		(43,676	)

		71,263			61,126

Other assets		76,804			74,956

Total assets	$	4,879,656		$	4,016,508

Liabilities
Current liabilities:
Accounts payable	$	273,083		$	212,514
Asset retirement obligations		1,609			1,903
Accrued liabilities		53,285			42,964
Accrued interest		20,045			17,595
Unrealized derivative loss		524,354			30,457

Total current liabilities		872,376			305,433


Bank debt		206,000			303,500
Subordinated notes		1,097,356			847,158
Deferred tax, net		535,575			590,786
Unrealized derivative loss		214,111			45,819
Deferred compensation liability		149,537			120,223
Asset retirement obligations and other liabilities		80,846			75,567
Commitments and contingencies

Stockholders’ equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par, 475,000,000 shares authorized, 155,091,558 issued at June 30, 2008 and 149,667,497 issued at December 31, 2007		1,551			1,497
Common stock held in treasury - 155,500 shares at June 30, 2008 and December 31, 2007		(5,334	)		(5,334	)
Additional paid-in capital		1,681,578			1,386,884
Retained earnings		325,488			371,800
Accumulated other comprehensive loss		(279,428	)		(26,825	)

Total stockholders’ equity		1,723,855			1,728,022

Total liabilities and stockholders’ equity	$	4,879,656		$	4,016,508

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,
	2008			2007			2008			2007
Revenues
Oil and gas sales	$	347,622		$	213,896		$	655,006		$	407,212
Transportation and gathering		1,224			511			2,353			695
Derivative fair value (loss) income		(198,410	)		28,766			(322,177	)		(13,854	)
Other		(359	)		341			20,233			2,302

Total revenues		150,077			243,514			355,415			396,355


Costs and expenses
Direct operating		37,228			24,816			70,178			50,230
Production and ad valorem taxes		16,056			11,230			29,896			21,642
Exploration		19,462			11,725			36,055			23,435
General and administrative		23,938			17,838			41,350			32,516
Deferred compensation plan		7,539			9,334			28,150			20,581
Interest expense		23,842			17,573			46,988			36,421
Depletion, depreciation and amortization		77,463			51,465			149,033			98,797

Total costs and expenses		205,528			143,981			401,650			283,622


(Loss) income from continuing operations before income taxes		(55,451	)		99,533			(46,235	)		112,733

Income tax (benefit) provision
Current		949			(101	)		1,835			283
Deferred		(21,818	)		34,449			(15,228	)		38,896

		(20,869	)		34,348			(13,393	)		39,179


(Loss) income from continuing operations		(34,582	)		65,185			(32,842	)		73,554

Discontinued operations, net of taxes		—			(979	)		—			63,789


Net (loss) income	$	(34,582	)	$	64,206		$	(32,842	)	$	137,343


Earnings per common share:
Basic — (loss) income from continuing operations	$	(0.23	)	$	0.45		$	(0.22	)	$	0.52
— discontinued operations		—			(0.01	)		—			0.45

— net (loss) income	$	(0.23	)	$	0.44		$	(0.22	)	$	0.97


Diluted — (loss) income from continuing operations	$	(0.23	)	$	0.43		$	(0.22	)	$	0.50
— discontinued operations		—			—			—			0.44

— net (loss) income	$	(0.23	)	$	0.43		$	(0.22	)	$	0.94


Dividends per common share	$	0.04		$	0.03		$	0.08		$	0.06

See accompanying notes.

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


	Six Months Ended
	June 30,
	2008			2007

Operating activities:
Net (loss) income	$	(32,842	)	$	137,343
Adjustments to reconcile to net cash provided from operating activities:
Income from discontinued operations		—			(63,789	)
Income from equity method investments		(19	)		(796	)
Deferred income tax (benefit) expense		(15,228	)		38,896
Depletion, depreciation and amortization		149,033			98,797
Unrealized derivative losses (gains)		2,691			(530	)
Mark-to-market losses on oil and gas derivatives not designated as hedges		299,227			45,789
Exploration dry hole costs		9,256			8,898
Amortization of deferred financing costs and other		1,488			1,076
Deferred and stock-based compensation		43,601			32,689
(Gain) loss on sale of assets and other		(19,972	)		119
Changes in working capital:
Accounts receivable		(94,657	)		(27,179	)
Inventory and other		(29,839	)		260
Accounts payable		22,384			(8,484	)
Accrued liabilities and other		9,739			3,385

Net cash provided from continuing operations		344,862			266,474
Net cash provided from discontinued operations		—			10,189

Net cash provided from operating activities		344,862			276,663


Investing activities:
Additions to oil and gas properties		(407,313	)		(375,360	)
Additions to field service assets		(19,895	)		(13,899	)
Acquisitions, net of cash acquired		(404,922	)		(282,054	)
Investing activities of discontinued operations		—			(7,374	)
Additional investment in other assets		(10,800	)		(93,312	)
Proceeds from disposal of assets and other		66,660			234,326
Purchases of marketable securities held by the deferred compensation plan		(5,848	)		—
Proceeds from the sale of marketable securities held by the deferred compensation plan		3,320			—

Net cash used in investing activities		(778,798	)		(537,673	)


Financing activities:
Borrowings on credit facility		678,000			570,000
Repayments on credit facility		(775,500	)		(575,500	)
Debt issuance costs		(5,510	)		(206	)
Dividends paid		(12,196	)		(8,635	)
Issuance of subordinated notes		250,000			—
Issuance of common stock		288,073			289,563
Purchases of common stock held by the deferred compensation plan		(73	)		—
Proceeds from the sale of common stock held by the deferred compensation plan		4,306			—
Other financing activities		2,891			—

Net cash provided from financing activities		429,991			275,222


Net (decrease) increase in cash and equivalents		(3,945	)		14,212
Cash and equivalents at beginning of period		4,018			2,382

Cash and equivalents at end of period	$	73		$	16,594

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,
	2008			2007		2008			2007

Net (loss) income	$	(34,582	)	$	64,206	$	(32,842	)	$	137,343
Net deferred hedging gains (losses), net of tax:
Contract settlements reclassified to income		31,278			1,165		27,628			(6,270	)
Change in unrealized deferred hedging gains (losses)		(200,173	)		11,396		(281,505	)		(20,132	)
Change in unrealized gains (losses) on securities held by deferred compensation plan, net of taxes		—			782		—			1,120

Comprehensive (loss) income	$	(203,477	)	$	77,549	$	(286,719	)	$	112,061

See accompanying notes.

RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

We are engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range Resources Corporation is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2) BASIS OF PRESENTATION

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2007 Annual Report on Form 10-K filed on February 27, 2008. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (“SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements.

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

(3) NEW ACCOUNTING STANDARDS

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

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income or loss. The statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. We adopted SFAS No. 159 as of January 1, 2008 and the impact of the adoption resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our investment securities held in our deferred compensation plan from accumulated other comprehensive loss to retained earnings. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. All investment securities held in our deferred compensation plans are reported in the balance sheet category called other assets and total $48.6 million at June 30, 2008 compared to $51.5 million at December 31, 2007. As of January 1, 2008, all of these investment securities are accounted for using the mark-to-market accounting method, are classified as “Trading” and all subsequent changes to fair value will be included in our statement of operations. For these securities, interest and dividends and the mark-to-market gains or losses are included in the income statement category called deferred compensation plan expense. For second quarter 2008, interest and dividends were $79,000 and the mark-to-market was a loss of $666,000. See Note 12 for other disclosures required by SFAS No. 159.

(4) ACQUISITIONS AND DISPOSITIONS

Acquisitions

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

In second quarter 2008, we purchased Barnett Shale properties for $40.5 million, which are subject to certain post-closing adjustments. In first quarter 2008, we purchased Barnett Shale properties for $281.5 million and an add-on to this acquisition in second quarter 2008 for $10.7 million. After recording asset retirement obligations and transaction costs of $646,000, the purchase price allocated to proved properties was $219.7 million and unproved properties was $73.2 million.

Dispositions

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

(5) DISCONTINUED OPERATIONS

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


	Three Months			Six Months
	Ended			Ended
	June 30,			June 30,
	2007			2007
Revenues:
Oil and gas sales	$	(1,096	)	$	15,187
Transportation and gathering		(58	)		10
Other		—			310
(Loss) gain on disposition of assets and other		(406	)		93,055

		(1,560	)		108,562

Costs and expenses:
Direct operating		(198	)		2,559
Production and ad valorem taxes		—			141
Exploration and other		146			212
Interest expense		—			845
Depletion, depreciation and amortization		—			6,672

		(52	)		10,429


(Loss) income from discontinued operations before income taxes		(1,508	)		98,133

Income tax (benefit) expense		(529	)		34,344


(Loss) income from discontinued operations, net of taxes	$	(979	)	$	63,789


Production:
Crude oil (bbls)		—			40,634
Natural gas (mcf)		—			1,990,277
Total (mcfe)		—			2,234,081

(6) INCOME TAXES

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Income tax (benefit) expense	$	(20,869	)	$	34,348		$	(13,393	)	$	39,179
Effective tax rate		37.6	%		34.5	%		29.0	%		34.8	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended June 30, 2008 and 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. For the six months ended June 30, 2008, our overall effective tax rate for continuing operations was different than the statutory rate of 35% due to state income taxes, a decrease in our deferred tax asset related to state tax credit carryforwards for additional tax expense of $1.5 million and a valuation allowance against a deferred tax asset related to our deferred compensation plan for additional tax expense of $2.5 million. For the six months ended June 30, 2007, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. We expect our effective tax rate to be approximately 38% for the remainder of 2008.

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

(7) EARNINGS PER COMMON SHARE

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,
	2008			2007			2008			2007
Numerator:
(Loss) income from continuing operations	$	(34,582	)	$	65,185		$	(32,842	)	$	73,554
(Loss) income from discontinued operations, net of taxes		—			(979	)		—			63,789

Net (loss) income	$	(34,582	)	$	64,206		$	(32,842	)	$	137,343


Denominator:
Weighted average shares outstanding		153,203			146,214			151,565			142,733
Stock held in the deferred compensation plan and treasury shares		(2,431	)		(1,045	)		(2,350	)		(1,089	)

Weighted average shares, basic		150,772			145,169			149,215			141,644


Effect of dilutive securities:
Weighted average shares outstanding		150,772			146,214			149,215			142,733
Employee stock options, SARs and stock held in the deferred compensation plan		—			3,968			—			3,883

Dilutive potential common shares for diluted earnings per share		150,772			150,182			149,215			146,616


Earnings per common share basic and diluted:
Basic — (loss) income from continuing operations	$	(0.23	)	$	0.45		$	(0.22	)	$	0.52
— discontinued operations		—			(0.01	)		—			0.45
— net (loss) income		(0.23	)		0.44			(0.22	)		0.97

Diluted — (loss) income from continuing operations	$	(0.23	)	$	0.43		$	(0.22	)	$	0.50
— discontinued operations		—			—			—			0.44
— net (loss) income		(0.23	)		0.43			(0.22	)		0.94

Due to our net loss from continuing operations for the three months and the six months ended June 30, 2008, we excluded all 10.0 million of outstanding stock options/SARs and restricted stock because the effect would have been anti-dilutive. Stock appreciation rights, or SARs, 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.

(8) SUSPENDED EXPLORATORY WELL COSTS

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


	June 30,			December 31,
	2008			2007

Beginning balance at January 1	$	15,053		$	9,984
Additions to capitalized exploratory well costs pending the determination of proved reserves		36,542			14,428
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(6,235	)		—
Capitalized exploratory well costs charged to expense		(3,598	)		(8,034	)
Divested wells		—			(1,325	)

Balance at end of period		41,762			15,053
Less exploratory well costs that have been capitalized for a period of one year or less		(38,014	)		(12,067	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	3,748		$	2,986

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		2			2

The $41.8 million of capitalized exploratory well costs at June 30, 2008 was incurred in 2008 ($31.8 million), in 2007 ($7.0 million) and in 2006 ($3.0 million).

(9) INDEBTEDNESS

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


	June 30,		December 31,
	2008		2007

Bank debt (4.9%)	$	206,000	$	303,500

Subordinated debt:
7.375% Senior Subordinated Notes due 2013, net of discount		197,781		197,602
6.375% Senior Subordinated Notes due 2015		150,000		150,000
7.5% Senior Subordinated Notes due 2016, net of discount		249,575		249,556
7.5% Senior Subordinated Notes due 2017		250,000		250,000
7.25% Senior Subordinated Notes due 2018		250,000		—

Total debt	$	1,303,356	$	1,150,658

Bank Debt

In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the $1.0 billion facility amount or the borrowing base. On June 30, 2008, the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. Subject to certain conditions, the facility amount may be increased to the borrowing base amount with twenty days notice. At June 30, 2008, the outstanding balance under the bank credit facility was $206.0 million and there was $794.0 million of borrowing capacity available. The loan matures October 25, 2012. Borrowing under the bank credit facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such data plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.0% to 0.5% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. On all LIBOR loans, we pay a varying rate per annum equal to

the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.0% and 1.75% per annum depending on the total outstanding under the bank credit facility relative to the borrowing base. We may elect, from time-to-time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any part of the base rate loans to LIBOR loans. The weighted average interest rate on the bank credit facility was 4.8% for the three months ended June 30, 2008 compared to 6.5% for the three months ended June 30, 2007. The weighted average interest rate on the bank credit facility for the six months ended June 30, 2008 was 4.9% compared to 6.5% in the same period of the prior year. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.25% and 0.375%. At June 30, 2008, the commitment fee was 0.25% and the interest rate margin was 1.0%. At July 21, 2008, the interest rate (including applicable margin) was 4.9%.

Senior Subordinated Notes

In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). Interest on the 7.25% Notes is payable semi-annually, in May and November, and is guaranteed by certain of our subsidiaries. We may redeem the 7.25% Notes, in whole or in part, at any time on or after May 1, 2013, at redemption prices of 103.625% of the principal amount as of May 1, 2013 and declining to 100.0% on May 1, 2016 and thereafter. Before May 1, 2011, we may redeem up to 35% of the original aggregate principal amount of the 7.25% Notes at a redemption price equal to 107.25% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that at least 65% of the original aggregate principal amount of the 7.25% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering.

Debt Covenants

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge or consolidate or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of greater than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at June 30, 2008.

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At June 30, 2008, we were in compliance with these covenants.

(10) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. A reconciliation of our liability for plugging, abandonment and remediation costs for the six months ended June 30, 2008 is as follows (in thousands):


	Six Months Ended
	June 30,
	2008

Beginning of period	$	75,308
Liabilities incurred		1,781
Liabilities settled		(657	)
Disposition of wells		(898	)
Accretion expense		2,863
Change in estimate		1,689

End of period	$	80,086

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

(11) CAPITAL STOCK

In May 2008, at our annual meeting, our shareholders approved an increase to our number of authorized shares of common stock. We now have authorized capital stock of 485 million shares, which includes 475 million shares of common stock and 10 million shares of preferred stock. The following is a summary of changes in the number of common shares outstanding since the beginning of 2007:


	Six		Year
	Months Ended		Ended
	June 30,		December 31,
	2008		2007

Beginning balance		149,667,497		138,931,565
Public offering		4,435,300		8,050,000
Stock options/SARs exercised		821,707		2,220,627
Restricted stock grants		158,066		408,067
In lieu of bonuses		8,988		29,483
Contributed to 401(k) plan		—		27,755

		5,424,061		10,735,932

Ending balance		155,091,558		149,667,497

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

Treasury Stock

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

(12) DERIVATIVE ACTIVITIES

At June 30, 2008, we had open swap contracts covering 54.1 Bcf of gas at prices averaging $8.57 per mcf. We also had collars covering 67.6 Bcf of gas at weighted average floor and cap prices of $8.17 to $9.47 per mcf and 4.6 million barrels of oil at weighted average floor and cap prices of $62.32 to $75.81 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, 2008, was a net unrealized pre-tax loss of $745.3 million. These contracts expire monthly through December 2009.

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


			Average
Period	Contract Type	Volume Hedged	Hedge Price

Natural Gas
2008	Swaps	155,000 Mmbtu/day	$8.73
2008	Collars	70,000 Mmbtu/day	$7.73 — $10.36
2009	Swaps	70,000 Mmbtu/day	$8.38
2009	Collars	150,000 Mmbtu/day	$8.28 — $9.27

Crude Oil
2008	Collars	9,000 bbl/day	$59.34 — $75.48
2009	Collars	8,000 bbl/day	$64.01 — $76.00

Under SFAS No. 133, every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying estimated market price at the determination date. Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive loss, which is later transferred to earnings when the hedged transaction occurs. If the derivative does not qualify as a hedge or is not designated as a hedge, the change in fair value of the derivative is recognized in earnings. As of June 30, 2008, an unrealized pre-tax derivative loss of $450.5 million was recorded in the balance sheet caption accumulated other comprehensive income (loss). This loss is expected to be reclassified into earnings in 2008 ($162.9 million) and 2009 ($287.6 million). The actual reclassification to earnings will be based on market prices at the contract settlement date.

For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly and are included as increases or decreases to oil and gas sales in the period the hedged production is sold. Oil and gas sales include $50.0 million and $44.8 million of losses in the three months and the six months ended June 30, 2008 compared to a loss of $1.8 million and a gain of $10.0 million in the three months and the six months ended June 30, 2007. Any ineffectiveness associated with these hedges is reflected in the income statement caption derivative fair value loss. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. The six months ended June 30, 2008 includes ineffective unrealized losses of $2.7 million compared to gains of $530,000 in the same period of 2007.

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

During third and fourth quarter 2007, in addition to the swaps and collars discussed above, we entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix a portion of our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $11.7 million at June 30, 2008 and expire through 2010.

Derivative Fair Value (Loss) Income

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007

Hedge ineffectiveness — realized	$	(490	)	$	—	$	215		$	—
— unrealized		558			749		(2,691	)		530
Change in fair value of derivatives that do not qualify for hedge accounting		(164,006	)		20,322		(299,227	)		(45,789	)
Realized (loss) gain on settlements — gas ^(a)		(28,256	)		7,695		(11,672	)		31,405
Realized loss on settlements — oil ^(a)		(6,216	)		—		(8,802	)		—

Derivative fair value (loss) income	$	(198,410	)	$	28,766	$	(322,177	)	$	(13,854	)


^(a)		These amounts represent the realized gains and losses on settled derivatives that do not qualify for hedge accounting, which before settlement are included in the category above called the change in fair value of derivatives that do not qualify for hedge accounting.

The combined fair value of derivatives included in our consolidated balance sheets as of June 30, 2008 and December 31, 2007 is summarized below (in thousands). Derivative activities are conducted with major financial and commodities trading institutions, which we believe are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. We have master netting agreements with our counterparties and the credit worthiness of our counterparties is subject to periodic review.


	June 30,			December 31,
	2008			2007
Derivative assets:
Natural gas — swaps	$	—		$	54,577
— collars		—			4,916
— basis swaps		4,821			1,082
Crude oil — collars		—			(6,475	)

	$	4,821		$	54,100


Derivative liabilities:
Natural gas — swaps	$	(236,417	)	$	6,594
— collars		(218,277	)		11,302
— basis swaps		6,874			(937	)
Crude oil — collars		(290,645	)		(93,235	)

	$	(738,465	)	$	(76,276	)

Fair Value Measurements

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

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

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

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

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

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


				Fair Value Measurements at June 30, 2008 Using
				Quoted Prices in		Significant Other			Significant
	Total Carrying			Active Markets for		Observable			Unobservable
	Value as of			Identical Assets		Inputs			Inputs
	June 30, 2008			(Level 1)		(Level 2)			(Level 3)

Trading securities held in the deferred compensation plans	$	48,640		$	48,640	$	—		$	—

Derivatives — swaps		(236,417	)		—		(236,417	)		—
— collars		(508,922	)		—		(508,922	)		—
— basis swaps		11,695			—		11,695			—

These items are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Our trading securities in Level 1 are exchange — traded and measured at fair value with a market approach using June 30, 2008 market values. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services to corroborate market data.

(13) EMPLOYEE BENEFIT AND EQUITY PLANS

We have six equity-based stock plans, of which two are active. Under the active plans, incentive and non-qualified options, SARs and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of outside, independent directors from the Board of Directors. All awards granted have been issued at prevailing market prices at the time of the grant. Information with respect to stock option and SARs activities is summarized below:


				Weighted
				Average
				Exercise
	Shares			Price

Outstanding on December 31, 2007		7,772,325		$	17.95
Granted		1,134,180			63.77
Exercised		(1,063,015	)		15.01
Expired/forfeited		(38,098	)		38.85

Outstanding on June 30, 2008		7,805,392		$	24.90

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


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

$ 1.29 — $ 9.99		1,982,863	2.09	$	4.75		1,982,863	$	4.75
10.00 — 19.99		1,906,310	1.83		16.25		1,906,310		16.25
20.00 — 29.99		1,313,046	2.75		24.36		699,616		24.24
30.00 — 39.99		1,466,498	3.74		33.97		404,507		34.59
40.00 — 49.99		17,540	4.31		42.59		360		41.01
50.00 — 59.99		743,970	4.62		58.57		180		58.60
60.00 — 69.99		28,427	4.88		65.33		—		—
70.00 — 75.00		346,738	4.89		75.00		26,484		75.00

Total		7,805,392	2.83	$	24.90		5,020,320	$	14.61

The weighted average fair value of an option/SAR to purchase one share of common stock granted during 2008 was $20.66. The fair value of each stock option/SAR granted during 2008 was estimated as of the date of grant using the Black-Scholes-Merton option-pricing model based on the following average assumptions: risk-free interest rate of 2.41%; dividend yield of 0.25%; expected volatility of 41%; and an expected life of 3.5 years.

As of June 30, 2008, the aggregate intrinsic value (the difference in value between exercise and market price) of the awards outstanding was $320.5 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable was $255.9 million and 2.23 years. As of June 30, 2008, the number of fully vested awards and awards expected to vest was 7.6 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $24.33 and 2.8 years and the aggregate intrinsic value was $317.0 million. As of June 30, 2008, unrecognized compensation cost related to the awards was $31.0 million, which is expected to be recognized over a weighted average period of 1.4 years.

Restricted Stock Grants

During the first six months of 2008, 312,500 shares of restricted stock (or non-vested shares) were issued to employees at an average price of $65.84 with a three-year vesting period and 10,800 shares were granted to our directors at a price of $75.00 with immediate vesting. In the first six months of 2007, we issued 407,400 shares of restricted stock as compensation to employees at an average price of $34.59 with a three year vesting period and 15,900 shares were granted to our directors at a price of $38.02 with immediate vesting. We recorded compensation expense related to restricted stock grants which is based upon the market value of the shares on the date of grant of $7.4 million in the first six months of 2008 compared to $4.2 million in the six-month period ended June 30, 2007. As of June 30, 2008, unrecognized compensation cost related to restricted stock awards was $31.0 million, which is expected to be recognized over the next 3 years. All of our restricted stock grants are held in our deferred compensation plans (see discussion below). The vesting of these shares is dependent only upon the employees’ continued service with us.

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


				Weighted
				Average Grant
	Shares			Date Fair Value

Non-vested shares outstanding at December 31, 2007		563,660		$	30.42
Granted		323,289			65.84
Vested		(208,101	)		37.73
Forfeited		(6,113	)		40.49

Non-vested shares outstanding at June 30, 2008		672,735		$	45.57

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 invest such amounts in Range common stock or make other investments at the individual’s discretion. The assets of the plan are held in a rabbi trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock granted and held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The vested portion of the stock held in the Rabbi Trust is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statement of operations. The assets of the Rabbi Trust, other than Range common stock, are invested in marketable securities and reported at market value in other assets on our consolidated balance sheet. Changes in the market value of the securities are charged or credited to deferred compensation plan expense each quarter. The deferred compensation liability on our balance sheet reflects the vested market value of the marketable securities and stock held in the Rabbi Trust. We recorded non-cash, mark-to-market expense related to our deferred compensation plan of $7.5 million and $28.1 million in the second quarter and the first six months of 2008 compared to $9.3 million and $20.6 million in the same periods of 2007.

(14) SUPPLEMENTAL CASH FLOW INFORMATION


	Six Months Ended
	June 30,
	2008		2007
	(in thousands)

Non-cash investing and financing activities included:
Asset retirement costs capitalized	$	3,175	$	2,145

Net cash provided from operating activities included:
Income taxes paid	$	2,320	$	44
Interest paid		43,189		35,776

The consolidated statement of cash flows for the six months ended June 30, 2008 excludes the following non-cash transactions: grants of 323,000 restricted shares, vesting of 208,000 restricted shares and forfeitures of 6,000 restricted shares.

(15) COMMITMENTS AND CONTINGENCIES

Litigation

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

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


	June 30,			December 31,
	2008			2007
	(in thousands)
Oil and gas properties:
Properties subject to depletion	$	4,783,732		$	4,172,151
Unproved properties		421,815			271,426

Total		5,205,547			4,443,577
Accumulated depreciation, depletion and amortization		(1,043,099	)		(939,769	)

Net capitalized costs	$	4,162,448		$	3,503,808


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

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


	Six Months
	Ended		Year Ended
	June 30,		December 31,
	2008		2007
	(in thousands)
Acquisitions:
Unproved leasehold	$	103,660	$	4,552
Proved oil and gas properties		230,036		253,064
Asset retirement obligations		251		3,301
Acreage purchases		67,577		78,095
Development		378,835		734,987
Exploration:
Drilling		53,945		40,567
Expense		34,193		39,872
Stock-based compensation expense		1,862		3,473
Gas gathering facilities		18,339		18,655

Subtotal		888,698		1,176,566

Asset retirement obligations		3,175		(7,075	)

Total costs incurred	$	891,873	$	1,169,491


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

(18) ACCOUNTING STANDARDS NOT YET ADOPTED

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

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” SFAS No. 141(R) replaces SFAS No. 141. The statement retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The statement will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009. We are currently evaluating provisions of this statement.

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

The following discussion should be read in conjunction with management’s discussion and analysis contained in our 2007 Annual Report on Form 10-K, as well as the consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. For additional risk factors affecting our business, see the information in Item 1A. Risk Factors, in our 2007 Annual Report on Form 10-K and subsequent filings. Except where noted, discussions in this report relate only to our continuing operations.

Critical Accounting Estimates and Policies

The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. There have been no significant changes to our critical accounting estimates or policies subsequent to December 31, 2007.

Results of Continuing Operations

Overview

Total revenues decreased 38% for second quarter 2008 over the same period of 2007. The decrease includes a 63% increase in oil and gas sales more than offset by a $227.2 million increase in derivative fair value loss. Oil and gas sales vary due to changes in volumes of production sold and realized commodity prices. For second quarter 2008, production increased 22% from the same period of the prior year with the continued success of our drilling program and our acquisitions. Realized prices were higher by 16% in second quarter 2008 when compared to second quarter of 2007. We believe prices will continue to remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy and the level of oil and gas production in North America and worldwide.

All of our expenses increased on both an absolute and per mcfe basis during second quarter 2008 due to higher overall industry costs, higher compensation expense resulting from additional employees, increased salaries and higher levels of activity. While overall costs were higher, the rate of inflation experienced in our industry during 2007 appears to have moderated for some goods and services, but is increasing for other goods such as steel. The availability of goods and services continues to be mixed. As we continue to have Marcellus wells shut-in waiting on pipeline and processing facilities, we expect to see continued upward pressure on our cost structure. The initial phase of the pipeline and processing infrastructure is expected to be completed in first quarter 2009.

Oil and Gas Sales, Production and Realized Price Calculation

Our oil and gas sales vary from quarter to quarter as a result of changes in realized commodity prices or volumes of production sold. Hedges included in oil and gas sales reflect settlement on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in the income statement caption called derivative fair value loss. The following table summarized the primary components of oil and gas sales for the three months and the six months ended June 30, 2008 and 2007 (in thousands):


	Three Months Ended													Six Months Ended
	June 30,													June 30,
	2008			2007			Change			%				2008			2007			Change			%

Oil wellhead	$	99,715		$	54,840		$	44,875			82	%		$	171,134		$	101,801		$	69,333			68	%
Oil hedges realized		(33,033	)		(1,936	)		(31,097	)		1,606	%			(48,425	)		(1,948	)		(46,477	)		2,386	%

Total oil revenue		66,682			52,904			13,778				26	%		122,709			99,853			22,856			23	%


Gas wellhead		279,054			149,602			129,452			87	%			493,570			275,926			217,644			79	%
Gas hedges realized		(16,926	)		87			(17,013	)		19,555	%			3,648			11,901			(8,253	)		69	%

Total gas revenue		262,128			149,689			112,439			75	%			497,218			287,827			209,391			73	%


NGL		18,812			11,303			7,509			66	%			35,079			19,532			15,547			80	%


Combined wellhead		397,581			215,745			181,836			84	%			699,783			397,259			302,524			76	%
Combined hedges		(49,959	)		(1,849	)		(48,110	)		2,602	%			(44,777	)		9,953			(54,730	)		550	%

Total oil and gas sales	$	347,622		$	213,896		$	133,726			63	%		$	655,006		$	407,212		$	247,794			61	%

Our production continues to grow through continued drilling success and additions from acquisitions. For second quarter 2008, our production volumes increased, from the same period of the prior year, 22% in our Appalachian Area, 20% in our Southwestern Area and 75% in our Gulf Coast Area. For the six months ended June 30, 2008, our production volumes increased, when compared to the prior year, 24% in our Appalachian Area, 23% in our Southwestern Area and 65% in our Gulf Coast Area. Our production for the three months and the six months ended June 30, 2008 and 2007 is shown below:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Production:
Crude oil (bbls)		829,144		881,641		1,583,689		1,720,129
NGLs (bbls)		335,231		280,407		647,731		553,537
Natural gas (mcf)		27,653,005		21,514,007		54,975,779		41,208,030
Total (mcfe) ^(a)		34,639,255		28,486,295		68,364,299		54,850,026
Average daily production:
Crude oil (bbls)		9,111		9,688		8,702		9,503
NGLs (bbls)		3,684		3,081		3,559		3,058
Natural gas (mcf)		303,879		236,418		302,065		227,669
Total (mcfe) ^(a)		380,651		313,036		375,628		303,039


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

Our average realized price (including all derivative settlements) received for oil and gas was $9.03 per mcfe in second quarter 2008 compared to $7.78 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlement for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months and the six months ended June 30, 2008 and 2007 are shown below:


	Three Months Ended				Six Months Ended,
	June 30,				June 30,
	2008		2007		2008		2007

Average sales prices (wellhead):
Crude oil (per bbl)	$	120.26	$	62.20	$	108.06	$	59.18
NGLs (per bbl)	$	56.12	$	40.31	$	54.16	$	35.29
Natural gas (per mcf)	$	10.09	$	6.95	$	8.98	$	6.70
Total (per mcfe) ^(a)	$	11.48	$	7.57	$	10.24	$	7.25

Average realized price (including derivatives that qualify for hedge accounting):
Crude oil (per bbl)	$	80.42	$	60.01	$	77.48	$	58.05
NGLs (per bbl)	$	56.12	$	40.31	$	54.16	$	35.29
Natural gas (per mcf)	$	9.48	$	6.96	$	9.04	$	6.98
Total (per mcfe) ^(a)	$	10.04	$	7.51	$	9.58	$	7.42

Average realized price (including all derivative settlements):
Crude oil (per bbl)	$	72.34	$	60.01	$	71.34	$	58.05
NGLs (per bbl)	$	56.12	$	40.31	$	54.16	$	35.29
Natural gas (per mcf)	$	8.46	$	7.32	$	8.85	$	7.75
Total (per mcfe) ^(a)	$	9.03	$	7.78	$	9.28	$	8.00

Average NYMEX prices ^(b)
Oil (per bbl)	$	123.98	$	65.03	$	111.66	$	61.65
Natural gas (per mcf)	$	10.80	$	7.56	$	9.45	$	7.26


^(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.

Derivative fair value (loss) gain includes a loss of $198.4 million in second quarter 2008 compared to a gain of $28.8 million in the same period of 2007. Some of our derivatives do not qualify for hedge accounting but are, to a degree, economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. All unrealized and realized gains and losses related to these contracts are included in the caption derivative fair value income (loss) gain. As a result of the sale of our Gulf of Mexico properties in first quarter 2007, the portion of our derivatives that were designated to our Gulf of Mexico production is being marked to market. In third quarter 2007, we entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges to market due to the anticipated sale of a portion of our East Texas properties, which occurred in first quarter 2008. The loss of hedge accounting treatment creates volatility in our revenues as gains and losses from non-hedge derivatives are included in total revenues and are not included in our balance sheet caption accumulated other comprehensive loss. Due to continued rising commodity prices for oil and natural gas in 2008, we reported a non-cash unrealized mark-to-market loss from our oil and gas derivatives of $164.0 million for the three months ended June 30, 2008. If commodity prices for oil and natural gas continue to rise, we would expect to incur additional realized and non-cash unrealized losses from our oil and gas hedges. If this occurs, our results of operations, net income (or loss) and earnings (or loss) per share may be adversely affected. Hedge ineffectiveness, also included in this income statement category, is associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133.

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007

Hedge ineffectiveness — realized^(c)	$	(490	)	$	—	$	215		$	—
— unrealized ^(a)		558			749		(2,691	)		530
Change in fair value of derivatives that do not qualify for hedge accounting ^(a)		(164,006	)		20,322		(299,227	)		(45,789	)
Realized (loss) gain on settlements — gas ^{(b) (c)}		(28,256	)		7,695		(11,672	)		31,405
Realized loss on settlements — oil ^{(b) (c)}		(6,216	)		—		(8,802	)		—

Derivative fair value (loss) gain	$	(198,410	)	$	28,766	$	(322,177	)	$	(13,854	)


^(a)		These amounts are unrealized and are not included in average sales price calculations.

^(b)		These amounts represent realized gains and losses on settled derivatives that do not qualify for hedge accounting.

^(c)		These settlements are included in average realized price calculations.

Other revenue for second quarter 2008 decreased to a loss of $360,000 from income of $341,000 in the same period of 2007. Second quarter 2008 included a loss of $632,000 from the sale of assets partially offset by income from equity method investments of $294,000. Other revenue for second quarter 2007 includes income from equity method investments of $385,000. Other revenue for the six months ended June 30, 2008 increased to $20.2 million from $2.3 million in the same period of 2007. The first six months of 2008 included a gain of $20.1 million from the sale of certain East Texas properties. Other revenue for the first six months of 2007 includes income from equity method investments of $796,000 and $537,000 of insurance proceeds.

Our costs have increased as we continue to grow. We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on an mcfe basis for the three months and the six months ended June 30, 2008 and 2007:


	Three Months Ended									Six Months Ended
	June 30,									June 30,
							%									%
	2008		2007		Change		Change			2008		2007		Change		Change

Direct operating expense	$	1.07	$	0.87	$	0.20		23	%	$	1.03	$	0.92	$	0.11		12	%
Production and ad valorem tax expense		0.46		0.39		0.07		18	%		0.44		0.39		0.05		13	%
General and administrative expense		0.69		0.63		0.06		10	%		0.60		0.59		0.01		2	%
Interest expense		0.69		0.62		0.07		11	%		0.69		0.66		0.03		5	%
Depletion, depreciation and amortization expense		2.24		1.81		0.43		24	%		2.18		1.80		0.38		21	%

Direct operating expense increased $12.4 million in second quarter 2008 to $37.2 million due to higher oilfield service costs and higher volumes. Our operating expenses are increasing as we add new wells from development and acquisitions and maintain production from our existing properties. We incurred $3.5 million ($0.10 per mcfe) of workover costs in second quarter 2008 versus $1.9 million ($0.07 per mcfe) in 2007. On a per mcfe basis, direct operating expenses for second quarter 2008 increased $0.20 or 23% from the same period of 2007 with the increase consisting primarily of higher workover costs ($0.03 per mcfe), higher equipment leasing costs ($0.03 per mcfe), higher personnel and related costs ($0.03 per mcfe), higher maintenance and well service costs ($0.06 per mcfe) along with higher overall industry costs, the curtailment of certain of our Barnett Shale production, and continued infrastructure build-out of our operations in the Marcellus Shale. Direct operating expenses increased $19.9 million in the first six months of 2008. We incurred $5.4 million ($0.08 per mcfe) of workover costs in the first six months of 2008 compared to $3.2 million ($0.06 per mcfe) in the first six months of 2007. On a per mcfe basis, direct operating expenses for the first six months 2008 increased $0.11 or 12% from the same period of 2007 with the increase consisting primarily of higher workover costs ($0.02 per mcfe), higher equipment leasing costs ($0.02 per mcfe), higher personnel and related costs ($0.02 per mcfe) along with higher overall industry costs and the curtailment of certain Barnett Shale production in the second quarter. The following table summarizes direct operating expenses per mcfe for the three months and the six months ended June 30, 2008 and 2007:


	Three Months Ended									Six Months Ended
	June 30,									June 30,
							%									%
	2008		2007		Change		Change			2008		2007		Change		Change

Lease operating expense	$	0.95	$	0.78	$	0.17		22	%	$	0.93	$	0.84	$	0.09		11	%
Workovers		0.10		0.07		0.03		43	%		0.08		0.06		0.02		33	%
Stock-based compensation (non-cash)		0.02		0.02		—		—	%		0.02		0.02		—		—	%

Total direct operating expenses	$	1.07	$	0.87	$	0.20		23	%	$	1.03	$	0.92	$	0.11		12	%

Production and ad valorem taxes are paid based on market prices and not hedged prices. For the second quarter, these taxes increased $4.8 million or 43% 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 $0.46 in second quarter 2008 from $0.39 in the same period of 2007 due to a 52% increase in pre-hedge prices. For the six months ended June, production and ad valorem taxes increased $8.3 million or 38% from the same period of the prior year due to higher volumes and prices. On a per mcfe basis, production and ad valorem taxes increased to $0.44 in the first six months of 2008 from $0.39 in the same period of the prior year due to a 41% increase in pre-hedge prices.

General and administrative expense for second quarter 2008 increased $6.1 million from the second quarter of the prior year due to higher salaries and benefits ($2.4 million), higher stock-based compensation ($1.5 million) and higher office expenses, including rent and information technology. For the six months ended June 30, 2008, general and administrative expenses increased $8.8 million from the same period of 2007 due to higher salaries and benefits ($4.1 million), higher stock-based compensation ($2.6 million) and higher office expense, including rent and information technology. The stock-based compensation represents amortization of restricted stock grants and stock option/SARs expense under SFAS No. 123(R). On a per mcfe basis, general and administrative expense increased from $0.63 in second quarter of the prior year to $0.69 in second quarter 2008. The following table summarizes general and administrative expenses per mcfe for second quarter and the six months of 2008 and 2007:


	Three Months Ended									Six Months Ended
	June 30,									June 30,
							%									%
	2008		2007		Change		Change			2008		2007		Change		Change
General and administrative	$	0.49	$	0.44	$	0.05		11	%	$	0.43	$	0.43	$	—		—	%
Stock-based compensation (non-cash)		0.20		0.19		0.01		5	%		0.17		0.16		0.01		6	%

Total general and administrative expenses	$	0.69	$	0.63	$	0.06		10	%	$	0.60	$	0.59	$	0.01		2	%

Interest expense for second quarter 2008 increased $6.3 million to $23.8 million due to the refinancing of certain debt from floating to higher fixed rates in third quarter 2007 and in second quarter 2008 and along with higher debt balances. In September 2007, we issued $250.0 million of 7.5% Notes due 2017, which added, $4.7 million of interest costs in second quarter 2008 and in May 2008, we issued $250.0 million of 7.25% Notes due 2018, which added $3.0 million of interest costs in second quarter 2008. The proceeds from both issuances were used to retire lower interest bank debt, to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for second quarter 2008 was $352.3 million compared to $357.7 million for second quarter 2007 and the weighted average interest rates were 4.8% in second quarter 2008 compared to 6.5% in second quarter 2007. Interest expense for the six months ended June 30, 2008 increased $10.6 million to $47.0 million due to the refinancing of certain debt from floating to higher fixed rates. The issuance of the 7.5% Notes due 2017 added $9.4 million of interest costs for the first six months of 2008 and the issuance of the 7.25% Notes added $3.0 million to interest costs for the six months ended June 30, 2008. Average debt outstanding on the credit facility for the six months ended June 30, 2008 was $446.0 million compared to $432.5 million in the first six months of 2007. The weighted average interest rate was 4.9% in the first six months of 2008 compared to 6.5% in the same period of 2007.

Depletion, depreciation and amortization (“DD&A”) increased $26.0 million, or 51%, to $77.5 million in second quarter 2008 with a 22% increase in production and a 16% increase in depletion rates. On a per mcfe basis, DD&A increased from $1.81 in second quarter 2007 to $2.24 in second quarter 2008. The increase in DD&A per mcfe is related to increasing drilling costs, higher acquisition costs and the mix of our production. The second quarter of 2008 also included higher acreage expiration expense of $4.3 million ($0.12 per mcfe) and an impairment of unproved acreage of $1.1 million ($0.03 per mcfe). DD&A expense increased $50.2 million or 51% in the first six months of 2008 with a 25% increase in production and a 17% increase in depletion rates. The first six months of 2008 also included higher acreage expiration expense of $5.5 million ($0.08 per mcfe) and an impairment of unproved acreage of $1.3 million ($0.02 per mcfe).

Our operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense and deferred compensation plan expenses. In the three months and the six months ended June 30, 2007 and 2008, stock-based compensation represents the amortization of restricted stock grants and expenses related to the adoption of SFAS No. 123(R). In second quarter 2008, stock-based compensation is a component of direct operating expense ($711,000), exploration expense ($1.1 million) and general and administrative expense ($6.9 million) for a total of $8.7 million. In second quarter 2007, stock-based compensation is a component of direct operating expense ($471,000), exploration expense ($920,000) and general and administrative expense ($5.4 million) for a total of $6.9 million. In the six months ended June 30, 2008, stock-based compensation is a component of direct operating expense ($1.3 million), exploration expense ($2.1 million) and general and administrative expense ($11.6 million) for a total of $15.2 million. In the six months 2007, stock-based compensation is a component of direct operating expense ($868,000), exploration expense ($1.7 million) and general and administrative expense ($9.0 million) for a total of $11.7 million.

Exploration expense increased $7.7 million in the second quarter and $12.6 million in the six month period of 2008 primarily due to higher seismic spending and increased personnel costs. The following table details our exploration-related expenses for the three months and the six months ended June 30, 2008 and 2007 (in thousands):


	Three Months Ended										Six Months Ended
	June 30,										June 30,
								%									%
	2008		2007		Change			Change			2008		2007		Change		Change

Dry hole expense	$	4,288	$	4,490	$	(202	)		4	%	$	9,256	$	8,898	$	358		4	%
Seismic		9,274		2,860		6,414			224	%		16,018		6,336		9,682		153	%
Personnel expense		3,425		2,330		1,095			47	%		6,063		4,327		1,736		40	%
Stock-based compensation expense		1,019		920		99			11	%		2,108		1,659		449		27	%
Delay rentals and other		1,456		1,125		331			29	%		2,610		2,215		395		18	%

Total exploration expense	$	19,462	$	11,725	$	7,737			66	%	$	36,055	$	23,435	$	12,620		54	%

Deferred compensation plan expense for second quarter 2008 decreased $1.8 million from the same period of the prior year primarily due to less of an increase in our stock price. Our stock price increased from $63.45 at March 31, 2008 to $65.54 at June 30, 2008. During the same period in the prior year, our stock price increased from $33.40 at March 31, 2007 to $37.41 at June 30, 2007. Deferred compensation plan expense for the six months ended June 30, 2008 was $28.1 million compared to $20.6 million in the same period of 2007 due to increases in our stock price. This non-cash expense relates to the increase or decrease in value of our common stock that is vested and held in the deferred compensation plan. The prior year also includes mark to market increases or decreases to the marketable securities held in our deferred compensation plans.

Income tax (benefit) expense for second quarter 2008 decreased to a benefit of $20.9 million, reflecting a 156% decrease in income from continuing operations before taxes compared to the same period of 2007. The second quarter of 2008 provided for a tax benefit at an effective rate of 37.6% compared to tax expense at an effective rate of 34.5% in the same period of 2007. Current income taxes of $949,000 included state income taxes of $699,000 and $250,000 of federal income taxes. Income tax expense for the six months ended June 30, 2008 decreased to a benefit of $13.4 million, reflecting an 141% decrease in income from continuing operations before taxes compared to the same period of 2007. The first six months of 2008 includes discrete tax items of a $2.5 million valuation allowance recorded against our deferred tax asset related to our deferred compensation plan and a $1.5 million charge related to a decrease in our deferred tax asset on state tax credit carryforwards. We expect our effective tax rate to be approximately 38% for the remainder of 2008.

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

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a committed bank credit facility, asset sales and access to both the debt and equity capital markets. During the six months ended June 30, 2008, our cash provided from continuing operations was $344.9 million and we spent $842.9 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $430.0 million. During the second quarter, we received proceeds of $250.0 million from the issuance of our 7.25% senior subordinated notes and net proceeds of $281.9 million from a common stock offering. At June 30, 2008, we had $73,000 in cash, total assets of $4.9 billion and a debt-to-capitalization ratio of 43.0%. Long-term debt at June 30, 2008 totaled $1.3 billion including $206.0 million of bank credit facility debt and $1.1 billion of senior subordinated notes. Available borrowing capacity under the bank credit facility at June 30, 2008 was $794.0 million.

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

Credit Arrangements

Effective April 1, 2008, our bank credit facility amount was increased from $900.0 million to $1.0 billion. On June 30, 2008, the bank credit facility had a $1.5 billion borrowing base and a $1.0 billion facility amount. Credit availability is equal to the lesser of the facility amount or the borrowing base resulting in credit availability of $731.0 million on July 21, 2008.

Our bank credit facility and our indentures governing our senior subordinated notes all contain covenants that, among other things, limit our ability to pay dividends and incur additional indebtedness. We were in compliance with these covenants at June 30, 2008. Please see Note 9 to our consolidated financial statements for additional information.

Cash Flow

Cash flows from operations primarily are affected by production and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We sell substantially all of our oil and gas production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. Any payments due counterparties under our derivative contracts should ultimately be funded by higher prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowing under the credit facility. As of June 30, 2008, we have entered into hedging agreements covering 51.3 Bcfe for 2008 and 97.8 Bcfe for 2009.

Net cash provided from continuing operations for the six months ended June 30, 2008 was $344.9 million compared to $276.7 million in the six months ended June 30, 2007. Cash flow from operations was higher than the prior year due to higher production from development activity and acquisitions. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in the consolidated statement of cash flows) in the six months ended June 30, 2008 was a negative $92.4 million compared to a negative $32.0 million in the same period of the prior year. Changes in working capital in the first six months of 2008 include a $25.0 million advance payment associated with our ongoing acreage acquisition effort in the Marcellus Shale. This acquisition is expected to close in the third quarter, along with other acquisitions in the aggregate amount of approximately $250.0 million.

Net cash used in investing for the six months ended June 30, 2008 was $778.8 million compared to $537.7 million in the same period of 2007. The 2008 period included $407.3 million of additions to oil and gas properties and $404.9 million of acquisitions, offset by proceeds of $66.7 million from asset sales. Acquisitions for six months of 2008 include the purchase of producing and non-producing Barnett Shale properties for $333.4 million. The 2007 period included $375.4 million of additions to oil and gas properties and $282.1 million of acquisitions, offset by proceeds of $234.3 million from asset sales.

Net cash provided from financing for the six months ended June 30, 2008 was $430.0 million compared to $275.2 million in the first six months of 2007. This increase was primarily due to the issuance of $250.0 million of 7.25% Notes in May 2008 partially offset by higher repayments on our bank credit facility. During the first six months of 2008, total debt increased $152.7 million.

Dividends

On June 2, 2008, the Board of Directors declared a dividend of four cents per share ($6.2 million) on our common stock, which was paid on June 30, 2008 to stockholders of record at the close of business on June 16, 2008.

Capital Requirements and Contractual Cash Obligations

The 2008 capital budget is currently set at $1.3 billion (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, 2008, $468.8 million of development and exploration spending was funded with internal cash flow and borrowings under our credit facility.

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

The following summarizes our significant obligations and commitments to make future contractual payments as of June 30, 2008. We have not guaranteed the debt or obligations of any other party, nor do we have any arrangements or relationships with other entities that could potentially result in unconsolidated debt or losses (in thousands):


	Payment Due by Period
			2009		2011
	2008		and 2010		and 2012		Thereafter		Total
Bank debt due 2012	$	—	$	—	$	206,000	$	—	$	206,000
7.375% senior subordinated notes due 2013		—		—		—		200,000		200,000
6.375% senior subordinated notes due 2015		—		—		—		150,000		150,000
7.5% senior subordinated notes due 2016		—		—		—		250,000		250,000
7.5% senior subordinated notes due 2017		—		—		—		250,000		250,000
7.25% senior subordinated notes due 2018		—		—		—		250,000		250,000
Operating leases		4,793		19,221		12,801		8,568		45,383
Seismic agreements		250		300		—		—		550
Derivative obligations at fair value		286,125		459,214		—		—		745,339
Asset retirement obligations		895		10,653		2,786		65,752		80,086

Total contractual obligations	$	292,063	$	489,388	$	221,587	$	1,174,320	$	2,177,358

Other Contingencies

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

Hedging — Oil and Gas Prices

We enter into hedging agreements to reduce the impact of oil and gas price volatility. At June 30, 2008, swaps were in place covering 54.1 Bcf of gas at prices averaging $8.57 per mcf. We also have collars covering 67.6 Bcf of gas at weighted average floor and cap prices of $8.17 and $9.47 per mcf and 4.6 million barrels of oil at weighted average floor and cap prices of $62.32 and $75.81 per barrel. Their fair value at June 30, 2008 (the estimated amount that would be realized on termination based on contract price and a reference price, generally NYMEX) was a net unrealized pre-tax loss of $745.3 million. The contracts expire monthly through December 2009. Settled transaction gains and losses for derivatives that qualify for hedge accounting are determined monthly and are included as increases or decreases in oil and gas sales in the period the hedged production is sold. In the first six months of 2008, oil and gas sales included realized hedging losses of $44.8 million compared to gains of $10.0 million in the same period of 2007.

At June 30, 2008, the following commodity derivative contracts were outstanding:


			Average
Period	Contract Type	Volume Hedged	Hedge Price

Natural Gas
2008	Swaps	155,000 Mmbtu/day	$	8.73
2008	Collars	70,000 Mmbtu/day	$	7.73 — $10.36
2009	Swaps	70,000 Mmbtu/day	$	8.38
2009	Collars	150,000 Mmbtu/day	$	8.28 — $9.27

Crude Oil
2008	Collars	9,000 bbl/day	$	59.34 — $75.48
2009	Collars	8,000 bbl/day	$	64.01 — $76.00

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

As a result of the sale of our Gulf of Mexico assets in first quarter 2007, a portion of derivatives, which were designated to our Gulf Coast production, are marked to market. In fourth quarter 2007, we began marking a portion of our oil hedges designated as Permian production to market due to the anticipated sale of a portion of our Permian properties that occurred in first quarter 2008. Derivatives that no longer qualify for hedge accounting are accounted for using the mark-to-market accounting method described above. As of June 30, 2008, derivatives on 61.9 Bcfe no longer qualify or are not designated for hedge accounting.

During third and fourth quarter 2007, in addition to the swaps and collars above, we entered into basis swap agreements that do not qualify as hedges for hedge accounting purposes and are marked to market. The price we receive for our production can be less than NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax gain of $11.7 million at June 30, 2008.

Interest Rates

At June 30, 2008, we had $1.3 billion of debt outstanding. Of this amount, $1.1 billion bore interest at fixed rates averaging 7.3%. Bank debt totaling $206.0 million bears interest at floating rates, which averaged 4.9% at June 30, 2008. The 30 day LIBOR rate on June 30, 2008 was 2.5%.

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 second quarter 2008, we received an average of $120.26 per barrel of oil and $10.09 per mcf of gas before derivative contracts compared to $62.20 per barrel of oil and $6.95 per mcf of gas in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and continued through the second quarter of 2008, 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 continue to increase in 2008.

Accounting Standards Not Yet Adopted

In March 2008, the FASB issued SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We are in the process of evaluating the impact of SFAS No. 161 on our Consolidated Financial Statements.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Market Risk

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

Commodity Price Risk

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

As of June 30, 2008, we had swaps in place covering 54.1 Bcf of gas. We also had collars covering 67.6 Bcf of gas and 4.6 million barrels of oil. These contracts expire monthly through December 2009. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of June 30, 2008, approximated a net unrealized pre-tax loss of $745.3 million.

At June 30, 2008, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Average Hedge Price		Fair Market Value
					(in thousands)
Natural Gas
2008	Swaps	155,000 Mmbtu/day	$	8.73	$	(136,062	)
2008	Collars	70,000 Mmbtu/day	$	7.73 — $10.36	$	(42,546	)
2009	Swaps	70,000 Mmbtu/day	$	8.38	$	(100,355	)
2009	Collars	150,000 Mmbtu/day	$	8.28 — $9.27	$	(175,731	)

Crude Oil
2008	Collars	9,000 bbl/day	$	59.34 — $75.48	$	(107,516	)
2009	Collars	8,000 bbl/day	$	64.01 — $76.00	$	(183,129	)

Other Commodity Risk

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. In addition to the collars and swaps detailed above, during third and fourth quarter 2007, we entered into basis swap agreements, which do not qualify for hedge accounting purposes and are marked to market. The price we receive for our gas production can be less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net realized pre-tax gain of $11.7 million at June 30, 2008.

In the first six months of 2008, a 10% reduction in oil and gas prices, excluding amounts fixed through designated hedging transactions, would have reduced revenue by $70.0 million. If oil and gas future prices at June 30, 2008 declined 10%, the unrealized hedging loss at that date would have decreased by $216.6 million.

Interest rate risk. At June 30, 2008, we had $1.3 billion of debt outstanding. Of this amount, $1.1 billion bore interest at fixed rates averaging 7.3%. Senior debt totaling $206.0 million bore interest at floating rates averaging 4.9%. A 1% increase or decrease in short-term interest rates would affect interest expense by approximately $2.1 million.

Item 4. CONTROLS AND PROCEDURES

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

PART II — Other Information

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On May 20, 2008, 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 total number of common shares authorized, to amend the 2005 Equity Based Compensation Plan including an increase to the number of shares to be issued and to ratify the appointment of Ernst & Young LLP as our registered public accounting firm for 2008. 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. John H. Pinkerton was elected Chairman of the Board and V. Richard Eales was appointed Lead Director by the Board of Directors.

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		133,742,264		2,736,889
Anthony V. Dub		131,749,647		4,729,506
V. Richard Eales		134,684,503		1,794,650
Allen Finkelson		130,788,925		5,690,228
Jonathan S. Linker		134,600,440		1,878,713
Kevin S. McCarthy		133,742,805		2,736,348
John H. Pinkerton		131,766,963		4,712,190
Jeffrey L. Ventura		131,767,557		4,711,596


							Broker
	Votes For		Against		Abstentions		Non-Votes
2. Increase authorized common shares		120,110,817		15,256,772		1,111,563		—
3. Amendments to our 2005 Equity-based plan		112,454,390		11,939,686		1,117,916		10,967,161
4. Appointment of Ernst & Young LLP		135,277,497		80,051		1,121,605		—

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) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation

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)

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

**		furnished 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
		Executive Vice President and Chief Financial Officer (Principal Financial Officer and duly authorized to sign this report on behalf of the Registrant)

July 23, 2008

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) and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation

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)

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

**		furnished herewith