Edgar Filing: RANGE RESOURCES CORP

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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, 2011


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)

Registrant’s telephone number, including area code
(817) 870-2601

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

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

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files).

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.

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

161,058,704 Common Shares were outstanding on July 22, 2011.

RANGE RESOURCES CORPORATION
FORM 10-Q
Quarter Ended June 30, 2011

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		24

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk		37

ITEM 4. Controls and Procedures		38

PART II — OTHER INFORMATION

ITEM 1A. Risk Factors		40

ITEM 6. Exhibits		41

PART I — FINANCIAL INFORMATION


ITEM 1.		Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	June 30, 2011			December 31, 2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	288,839		$	2,848
Accounts receivable, less allowance for doubtful accounts of $3,842 and $5,001		66,772			76,683
Unrealized derivative gain		53,674			123,255
Assets of discontinued operations		16,351			876,304
Inventory and other		11,912			21,352
Deferred tax asset		6,340			—

Total current assets		443,888			1,100,442


Unrealized derivative gain		11,843			—
Equity method investments		139,935			155,105
Natural gas and oil properties, successful efforts method		5,999,665			5,390,391
Accumulated depletion and depreciation		(1,447,300	)		(1,306,378	)

		4,552,365			4,084,013

Transportation and field assets		121,905			134,980
Accumulated depreciation and amortization		(64,459	)		(60,931	)

		57,446			74,049
Other assets		104,430			84,977

Total assets	$	5,309,907		$	5,498,586


Liabilities
Current liabilities:
Accounts payable	$	246,549		$	289,109
Asset retirement obligations		4,020			4,020
Accrued liabilities		53,077			60,082
Deferred tax liability		—			11,848
Accrued interest		29,013			32,189
Unrealized derivative loss		—			352
Current liabilities of discontinued operations		19,381			32,962

Total current liabilities		352,040			430,562

Bank debt		—			274,000
Subordinated notes		1,787,398			1,686,536
Deferred tax liability		685,200			672,041
Unrealized derivative loss		4,427			13,412
Deferred compensation liability		159,024			134,488
Asset retirement obligations and other liabilities		76,891			59,885
Long-term liabilities of discontinued operations		—			3,901
Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 160,998,360 issued at June 30, 2011 and 160,113,608 issued at December 31, 2010		1,610			1,601
Common stock held in treasury, 175,653 shares at June 30, 2011 and 204,556 shares at December 31, 2010		(6,489	)		(7,512	)
Additional paid-in capital		1,848,767			1,820,503
Retained earnings		355,099			341,699
Accumulated other comprehensive income		45,940			67,470

Total stockholders’ equity		2,244,927			2,223,761

Total liabilities and stockholders’ equity	$	5,309,907		$	5,498,586

See the accompanying notes.

RANGE RESOURCES CORPORATION

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues and other income
Natural gas, NGL and oil sales	$	256,687		$	173,153		$	483,568		$	360,826
Transportation and gathering		(1,041	)		663			(728	)		2,744
Derivative fair value income		53,039			6,546			12,205			48,879
(Loss) gain on the sale of assets		(1,621	)		10,176			(1,482	)		78,089
Other		(435	)		637			642			(938	)

Total revenues and other income		306,629			191,175			494,205			489,600


Costs and expenses
Direct operating		28,509			21,171			57,226			43,007
Production and ad valorem taxes		7,550			5,663			14,429			12,205
Exploration		11,592			14,420			38,779			28,559
Abandonment and impairment of unproved properties		18,900			9,727			35,437			16,278
General and administrative		39,120			35,836			73,079			64,006
Termination costs		—			—			—			7,938
Deferred compensation plan		(5,778	)		(14,135	)		24,852			(19,847	)
Interest expense		31,383			21,271			56,162			42,202
Loss on early extinguishment of debt		18,580			—			18,580			—
Depletion, depreciation and amortization		78,294			67,813			150,510			132,620
Impairment of proved properties		—			—			—			6,505

Total costs and expenses		228,150			161,766			469,054			333,473


Income from continuing operations before income taxes		78,479			29,409			25,151			156,127

Income tax expense
Current		8			—			8			—
Deferred		32,695			11,763			12,798			60,775

Total income tax expense		32,703			11,763			12,806			60,775


Income from continuing operations		45,776			17,646			12,345			95,352
Discontinued operations, net of taxes		5,517			(8,594	)		13,915			(8,721	)

Net income	$	51,293		$	9,052		$	26,260		$	86,631


Income per common share
Basic-income from continuing operations	$	0.28		$	0.11		$	0.08		$	0.59
— discontinued operations		0.04			(0.05	)		0.08			(0.05	)

— net income	$	0.32		$	0.06		$	0.16		$	0.54


Diluted-income from continuing operations	$	0.28		$	0.11		$	0.08		$	0.59
— discontinued operations		0.04			(0.05	)		0.08			(0.05	)

— net income	$	0.32		$	0.06		$	0.16		$	0.54


Dividends per common share	$	0.04		$	0.04		$	0.08		$	0.08


Weighted average common shares outstanding
Basic		157,997			156,820			157,772			156,608
Diluted		158,833			158,472			158,729			158,601

See the accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)


	Six Months Ended June 30,
	2011			2010
Operating activities
Net income	$	26,260		$	86,631
Adjustments to reconcile net cash provided from operating activities:
(Gain) loss from discontinued operations		(13,915	)		8,721
Loss from equity method investments, net of distributions		19,259			985
Deferred income tax expense		12,798			60,775
Depletion, depreciation, amortization and proved property impairment		150,510			139,126
Exploration dry hole costs		6			—
Mark-to-market gain on gas and oil derivatives not designated as hedges		(8,103	)		(42,169	)
Abandonment and impairment of unproved properties		35,437			16,278
Unrealized derivative gain		(6,502	)		(11	)
Allowance for bad debts		(404	)		—
Deferred and stock-based compensation		48,161			5,866
Amortization of deferred financing costs, loss on extinguishment of debt and other		19,891			2,367
Loss (gain) on sale of assets		1,483			(78,089	)
Changes in working capital:
Accounts receivable		(4,159	)		8,061
Inventory and other		2,747			338
Accounts payable		(6,222	)		13,859
Accrued liabilities and other		(436	)		(14,038	)

Net cash provided from continuing operations		276,811			208,700
Net cash provided from discontinued operations		36,802			51,737

Net cash provided from operating activities		313,613			260,437


Investing activities
Additions to oil and gas properties		(535,307	)		(322,395	)
Additions to field service assets		(2,830	)		(10,270	)
Acreage and proved property purchases		(73,070	)		(187,192	)
Other assets		—			(45	)
Proceeds from disposal of assets		23,409			318,632
Purchase of marketable securities held by the deferred compensation plan		(8,832	)		(14,553	)
Proceeds from the sales of marketable securities held by the deferred compensation plan		6,620			13,296

Net cash used in investing activities from continuing operations		(590,010	)		(202,527	)
Investing activities of discontinued operations		835,147			(27,011	)

Net cash provided from (used in) investing activities		245,137			(229,538	)


Financing activities
Borrowing on credit facilities		490,826			371,000
Repayment on credit facilities		(764,826	)		(220,000	)
Dividends paid		(12,860	)		(12,768	)
Issuance of common stock		554			5,785
Issuance of subordinated notes		500,000			—
Repayment of subordinated notes		(413,332	)		—
Debt issuance costs		(21,653	)		—
Change in cash overdrafts		(58,265	)		(13,385	)
Proceeds from the sales of common stock held by the deferred compensation plan		6,797			4,560

Net cash (used in) provided from financing activities		(272,759	)		135,192


Increase in cash and equivalents		285,991			166,091
Cash and cash equivalents at beginning of period		2,848			767

Cash and cash equivalents at end of period	$	288,839		$	166,858

See the accompanying notes.

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010

Net income	$	51,293		$	9,052		$	26,260		$	86,631
Other comprehensive (loss) income:
Realized gain on hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of taxes		(15,178	)		(11,371	)		(39,068	)		(12,124	)
Change in unrealized deferred hedging gains (losses), net of taxes		17,424			(4,257	)		17,537			48,325

Total comprehensive income (loss)	$	53,539		$	(6,576	)	$	4,729		$	122,832

See the accompanying notes.

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

We are a Fort Worth, Texas-based independent natural gas and oil company engaged in the exploration, development and acquisition of natural gas and oil properties, mostly in the Appalachia and the Southwest regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Range Resources Corporation is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

(2) BASIS OF PRESENTATION

Presentation

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2010 Annual Report on Form 10-K filed on March 1, 2011 and our current report on Form 8-K filed on May 6, 2011. The results of operations for the quarter and the six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year. 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 (“U.S. GAAP”) for complete financial statements.

Discontinued Operations

In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale assets. In April 2011, we completed the sale of most of these assets. We expect to close on the remainder of the sale in the third quarter 2011. We have classified the assets and liabilities of these assets as discontinued operations in the accompanying consolidated balance sheets along with the historic results of these operations as discontinued operations, net of tax, in the accompanying consolidated statements of operations. See also Note 4 and 5 for more information regarding the sale of our Barnett Shale assets.

(3) NEW ACCOUNTING STANDARDS

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”).” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance will require prospective application. We are currently evaluating the effect that the provisions of this pronouncement will have on our financial statements.

In June 2011, the FASB issued ASU No. 2011-05, “Presentation of Comprehensive Income” which was issued to enhance comparability between entities that report under U.S. GAAP and IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption of the new guidance is permitted and full retrospective application is required. We are currently evaluating the effect that the provisions of this pronouncement will have on our financial statements.

(4) DISPOSITIONS

2011 Asset Sales

In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale natural gas properties in the Barnett Shale Play located in North Central Texas (Dallas, Denton, Ellis, Hill, Hood, Johnson, Parker, Tarrant and Wise Counties), which also included the assumption of certain derivative contracts by the buyer and is subject to normal post closing adjustments. We closed substantially all of this sale in second quarter 2011, for gross cash proceeds of approximately

$877.0 million, including the derivative contracts assumed. This transaction is subject to additional closings on certain properties subject to preferential rights along with other post-closing adjustments. We expect to close the remainder of the sale in the third quarter 2011. The agreements have an effective date of February 1, 2011 and consequently operating net revenues after February 1, 2011 were a downward adjustment to the selling price. We recorded a pretax gain of $3.8 million in discontinued operations related to this sale. In the accompanying December 31, 2010 balance sheet, we have classified these assets and liabilities as discontinued operations. As indicated in Note 2 and 5, the historic results of our Barnett operations are presented as discontinued operations.

As part of the sale of our Barnett properties, certain derivative contracts were assumed by the buyer. This resulted in a loss of $1.7 million in second quarter 2011. Under cash flow hedge accounting, an $18.8 million pretax gain related to these hedges is included in accumulated other comprehensive income at June 30, 2011 and will be recognized in earnings during the remainder of 2011 as the hedged production occurs. The hedges assumed as part of the sale were not designated to our Barnett production and were sold to balance our volumes hedged.

2010 Asset Sales

In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio. We closed approximately 90% of the sale in March 2010 and closed the remainder in June 2010. Proceeds received in first six months 2010 were approximately $323.0 million and we recorded a gain of $77.4 million in continuing operations. The agreement had an effective date of January 1, 2010, and consequently operating net revenues after January 1, 2010 were a downward adjustment to the selling price. The proceeds we received were placed in a like-kind exchange account and in June 2010, we used a portion of the proceeds to purchase proved and unproved natural gas properties in Virginia. In September 2010, the like-kind exchange account was closed and the balance of these proceeds ($135.0 million) was used to repay amounts outstanding under our bank credit facility.

(5) DISCONTINUED OPERATIONS

The following table presents the components of our Barnett operations as discontinued operations for the three months and the six months ended June 30, 2011 and 2010 (in thousands):


	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
Revenues and other income
Natural gas, NGL and oil sales	$	10,777	$	33,631		$	53,034	$	82,718
Transportation and gathering		1		11			6		23
Gain on the sale of assets		3,820		—			3,820		955
Other		—		—			4		—

Total revenues and other income		14,598		33,642			56,864		83,696


Costs and expenses
Direct operating		2,169		8,604			10,446		17,808
Production and ad valorem taxes		184		2,427			1,250		3,955
Exploration		5		53			37		549
Abandonment and impairment of unproved properties		—		3,770			—		9,626
Interest expense		3,715		9,508			14,791		18,864
Depletion, depreciation and amortization		14		23,184			8,894		47,003

Total costs and expenses		6,087		47,546			35,418		97,805


Income (loss) from discontinued operations before income taxes		8,511		(13,904	)		21,446		(14,109	)

Income tax expense (benefit)
Current		—		—			—		—
Deferred		2,994		(5,310	)		7,531		(5,388	)

Total income tax expense (benefit)		2,994		(5,310	)		7,531		(5,388	)


Net income (loss) from discontinued operations	$	5,517	$	(8,594	)	$	13,915	$	(8,721	)

The carrying values of our Barnett operations are included in discontinued operations in the accompanying consolidated balance sheets which are comprised of the following (in thousands):


	June 30,		December 31,
	2011		2010
Composition of assets of discontinued operations:
Natural gas and oil properties, net	$	12,546	$	838,044
Transportation and field assets, net		—		684
Accounts receivable		3,805		29,300
Unrealized derivative gain		—		8,195
Inventory and other		—		81

Total assets of discontinued operations	$	16,351	$	876,304


Composition of liabilities of discontinued operations:
Account payable	$	12,592	$	23,366
Accrued liabilities		6,789		9,596

Total current liabilities of discontinued operations	$	19,381	$	32,962


Asset retirement obligations	$	—	$	1,980
Other liabilities		—		1,921

Total long-term liabilities of discontinued operations	$	—	$	3,901

(6) INCOME TAXES

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


	Three Months Ended						Six Month Ended
	June 30,						June 30,
	2011			2010			2011			2010

Income tax expense	$	32,703		$	11,763		$	12,806		$	60,775
Effective tax rate		41.7	%		40.0	%		50.9	%		38.9	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the three months ended June 30, 2011 and 2010, our overall effective tax rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences. For the six months ended June 30, 2011 and 2010, our overall effective rate on pre-tax income from continuing operations was different than the statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences.

(7) INCOME FROM CONTINUING OPERATIONS PER COMMON SHARE

Basic income or loss from continuing operations per share is computed as (i) income or loss from continuing operations (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss from continuing operations per share is computed as (i) basic income or loss from continuing operations attributable to common shareholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. The following table sets forth a reconciliation of income from continuing operations to basic income from continuing operations attributable to common shareholders and to diluted income from continuing operations attributable to common shareholders and a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands except per share amounts):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Numerator:
Income from continuing operations	$	45,776		$	17,646		$	12,345		$	95,352
Less: Basic income allocable to participating securities ^(a)		(808	)		(159	)		(220	)		(1,491	)

Basic income from continuing operations attributable to common shareholders		44,968			17,487			12,125			93,861
Diluted adjustments to income allocable to participating securities ^(a)		4			—			1			16

Diluted income from continuing operations attributable to common shareholders	$	44,972		$	17,487		$	12,126		$	93,877


Denominator:
Weighted average common shares outstanding — basic		157,997			156,820			157,772			156,608
Effect of dilutive securities:
Employee stock options and SARs		836			1,652			957			1,993

Weighted average common shares — diluted		158,833			158,472			158,729			158,601


Income from continuing operations per common share:
Basic — net income	$	0.28		$	0.11		$	0.08		$	0.59
Diluted — net income	$	0.28		$	0.11		$	0.08		$	0.59


^(a)		Restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Restricted stock awards do not participate in undistributed net losses.

The weighted average common shares — basic for the three months ended June 30, 2011 and 2010 exclude 2.8 million shares of restricted stock which is held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Weighted average common shares-basic for the six months ended June 30, 2011 excludes 2.9 million shares of restricted stock compared to 2.7 million for the six months ended June 30, 2010. SARs of 860,000 for the three months ended June 30, 2011 and 1.0 million for the six months ended June 30, 2011 were outstanding but not included in the computations of diluted income from continuing operations per share because the grant prices of the SARs were greater than the average market price of the common shares. SARs of 1.1 million for the three months ended June 30, 2010 and 1.1 million for the six months ended June 30, 2010 were outstanding but not included in the computations of diluted income from continuing operations per share because the grant prices of the SARs were greater than the average market price of the common shares.

(8) SUSPENDED EXPLORATORY WELL COSTS

The following table reflects the changes in capitalized exploratory well costs for the six months ended June 30, 2011 and the year ended December 31, 2010 (in thousands):


	June 30,			December 31,
	2011			2010
Beginning balance at January 1	$	23,908		$	19,052
Additions to capitalized exploratory well costs pending the determination of proved reserves		35,463			28,897
Reclassifications based on determination of proved reserves		(11,619	)		(24,041	)
Capitalized exploratory well costs charged to expense		—			—

Balance at end of period		47,752			23,908
Less exploratory well costs that have been capitalized for a period of one year or less		(42,519	)		(13,181	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	5,233		$	10,727

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		3			4

As of June 30, 2011, of the $5.2 million of capitalized exploratory well costs that have been capitalized for more than one year, two of the wells are Marcellus Shale wells and are waiting on the completion of pipelines. The following provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of June 30, 2011 (in thousands):


	Total		2011		2010		2009		2008

Capitalized exploratory well costs that have been capitalized for more than one year	$	5,233	$	255	$	334	$	3,065	$	1,579

(9) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (in thousands). No interest expense was capitalized during the three months and the six months ended June 30, 2011 and 2010.


	June 30,		December 31,
	2011		2010
Bank debt	$	—	$	274,000

Subordinated debt:
6.375% Senior Subordinated Notes due 2015		—		150,000
7.5% Senior Subordinated Notes due 2016, net of discount		—		249,683
7.5% Senior Subordinated Notes due 2017		250,000		250,000
7.25% Senior Subordinated Notes due 2018		250,000		250,000
8.0% Senior Subordinated Notes due 2019, net of discount		287,398		286,853
6.75% Senior Subordinated Notes due 2020		500,000		500,000
5.75% Senior Subordinated Notes due 2021		500,000		—

Total debt	$	1,787,398	$	1,960,536

Bank Debt

In February 2011, 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. Our new borrowing base was set without our Barnett Shale assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On June 30, 2011, the borrowing base was $2.0 billion and our facility amount was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-seven commercial banks with no one bank holding more than 7% of the total facility. The facility amount may be increased up to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility amount increase. At June 30, 2011, we had no outstanding balances under our bank credit facility and we had $13.9 million of undrawn letters of credit leaving approximately $1.5 billion of borrowing capacity available under the facility amount. The facility matures in February 2016. Borrowing under the bank credit facility can either be the Alternate Base Rate (as defined) plus a spread ranging from 0.50% to 1.50% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.50% to 2.50%. The applicable spread is dependent upon borrowings 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 2.0% for the three months ended June 30, 2011 compared to 2.2% for the three months ended June 30, 2010. The weighted average interest rate on the bank credit facility was 2.2% for the six months ended June 30, 2011 compared to 2.2% for the six months ended June 30, 2010. A commitment fee is paid on the undrawn balance based on an annual rate of between 0.375% and 0.50%. At June 30, 2011, the commitment fee was 0.375%.

Senior Subordinated Notes

In May 2011, we issued $500.0 million aggregate principal amount of 5.75% senior subordinated notes due 2021 (“5.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 5.75% Notes were issued at par. Interest on the 5.75% Notes is payable semi-annually in June and December and is guaranteed by all of our current subsidiaries. We may redeem the 5.75% Notes, in whole or in part, at any time on or after June 1, 2016, at redemption prices of 102.875% of the principal amount as of June 1, 2016 declining to 100.0% on June 1, 2019 and thereafter. Before June 2014, we may redeem up to 35% of the original aggregate principal amount of the 5.75% Notes at a redemption price equal to 105.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.75% 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. On closing, we used $112.9 million of the proceeds to purchase our 6.375% senior subordinated notes due 2015 and $207.1 million of the proceeds to purchase our 7.5% senior subordinated notes due 2016 as part of the tender offer and redemption described below.

On May 11, 2011, we commenced cash tender offers to purchase the entire outstanding $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 and $250.0 million principal amount of our 7.5% senior subordinated notes due 2016. On May 25, 2011, after the expiration of the tender offers, we accepted for purchase $108.9 million in principal of the 2015 notes at 102.375% of par and $198.8 million in principal of the 2016 notes for 104.00% of par. We subsequently called the remaining 2015 and 2016 notes, redeeming all of the remaining outstanding 2015 notes ($41.1 million) at 102.125% of par on June 24, 2011 and redeeming all of the remaining outstanding 2016 notes ($51.2 million) at 103.75% of par on June 24, 2011. During the second quarter 2011, we recognized an $18.6 million loss on extinguishment of debt, including transaction call premium cost as well as expensing of deferred financing cost on repurchased debt.

Debt Covenants

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at June 30, 2011.

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other 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, 2011, we were in compliance with these covenants.

(10) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent 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. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. A reconciliation of our liability for plugging, abandonment and remediation costs for the six months ended June 30, 2011 is as follows (in thousands):


	Six Months
	Ended
	June 30,
	2011
Beginning of period — continuing operations	$	60,693
Liabilities incurred		1,447
Liabilities settled		(1,625	)
Accretion expense — continuing operations		2,580
Change in estimate		11,270

End of period — continuing operations	$	74,365

Accretion expense is recognized as a component of depreciation, depletion and amortization expense on our consolidated statements of operations.

(11) CAPITAL STOCK

We 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 2010:


	Six Months		Year
	Ended		Ended
	June 30,		December 31,
	2011		2010
Beginning balance		159,909,052		158,118,937
Stock options/SARs exercised		558,161		991,988
Restricted stock grants		326,591		405,127
Treasury shares issued		28,903		12,771
Shares issued for acreage purchases		—		380,229

Ending balance		160,822,707		159,909,052

Treasury Stock

The Board of Directors has approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities and on June 30, 2011, we have $6.8 million remaining under this authorization.

(12) DERIVATIVE ACTIVITIES

We use commodity—based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap, collar or call option contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. Historically, our derivative activities have consisted of collars and fixed price swaps. At June 30, 2011, we had open swap contracts covering 25.6 Bcf of natural gas at prices averaging $5.00 per mcf and 3.1 million barrels of NGLs (the C5 component of NGLs) at prices averaging $103.24 per barrel. At June 30, 2011, we had collars covering 189.1 Bcf of natural gas at weighted average floor and cap prices of $5.27 to $5.93 per mcf and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 to $80.00 per barrel. At June 30, 2011, we also had sold call options for 2.7 million barrels of oil at a weighted average price of $83.15. In first quarter 2011, we entered into NGL derivative swap contracts for the natural gasoline (or C5) component of natural gas liquids. The fair value of our commodity derivatives, 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, 2011, was a net unrealized pre-tax gain of $61.1 million. These contracts expire monthly through December 2013.

The following table sets forth our derivative volumes and average hedge prices as of June 30, 2011:


			Average
Period	Contract Type	Volume Hedged	Hedge Price
Natural Gas
2012	Swaps	70,192 Mmbtu/day	$	5.00
2011	Collars	333,200 Mmbtu/day	$	5.38-$6.23
2012	Collars	189,641 Mmbtu/day	$	5.32-$5.91
2013	Collars	160,000 Mmbtu/day	$	5.09-$5.65

Crude Oil
2012	Collars	2,000 bbls/day	$	70.00-$80.00
2011	Call options	5,500 bbls/day	$	80.00
2012	Call options	4,700 bbls/day	$	85.00

NGLs (Natural gasoline)
2011	Swaps	7,000 bbls/day	$	104.17
2012	Swaps	5,000 bbls/day	$	102.59

Every derivative instrument is recorded on the accompanying balance sheets 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 market price at the determination date. Changes in the fair value of derivatives that qualify for hedge accounting are recorded as a component of accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets, which is later transferred to natural gas, NGL and oil sales when the underlying physical transaction occurs and the hedging contract is settled. Amounts included in AOCI at June 30, 2011 and December 31, 2010 relate solely to our commodity derivative activities. As of June 30, 2011, an unrealized pre-tax derivative gain of $73.5 million was recorded in AOCI. This gain is expected to be reclassified into earnings as a $44.1 million gain in 2011, a $21.9 million gain in 2012 and a $7.5 million gain in 2013. 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 natural gas, NGL and oil sales in the period the hedged production is sold. Natural gas, NGL and oil sales include $24.3 million of gains in the three months ended June 30, 2011 compared to gains of $18.3 million in the same period of 2010 related to settled hedging transactions. Natural gas, NGL and oil sales include $53.9 million of gains in the six months ended June 30, 2011 compared to gains of $19.6 million in the same period of 2010 related to settled hedges. Any ineffectiveness associated with these hedge derivatives is included in derivative fair value income in the accompanying consolidated statements of operations. 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 three months ended June 30, 2011 includes ineffective gains (unrealized and realized) of $7.5 million compared to gains of $265,000 in the same period of 2010. The six months ended June 30, 2011 includes ineffective gains (unrealized and realized) of $9.0 million compared to losses of $341,000 in the same period of 2010.

Through June 30, 2011, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGL and oil sales when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in derivative fair value income (loss) in the accompanying consolidated statements of operations. During the first three and six months of 2011 or 2010, there were no gains or losses recorded due to the discontinuance of hedge accounting treatment for these derivatives.

Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge but provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas and oil production. 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 derivative fair value income in the accompanying consolidated statements of operations (for additional information see table below).

Derivative Fair Value Income

The following table presents information about the components of derivative fair value income in the three and six months ended June 30, 2011 and 2010 (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Hedge ineffectiveness — realized	$	1,576		$	5		$	2,522		$	(352	)
— unrealized		5,934			260			6,502			11
Change in fair value of derivatives that do not qualify for hedge accounting^(a)		48,139			(4,409	)		8,103			42,169
Realized gain on settlements — gas^{(a) (b)}		3,484			10,690			3,090			7,051
Realized loss on settlements — oil^{(a) (b)}		(6,094	)		—			(8,012	)		—

Derivative fair value income	$	53,039		$	6,546		$	12,205		$	48,879


^(a)		Derivatives that do not qualify for hedge accounting.

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

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of June 30, 2011 and December 31, 2010 is summarized below (in thousands). As of June 30, 2011 we have conducted commodity derivative activities with ten financial institutions, of which all but one are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. In our accompanying consolidated balance sheets, derivative assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty.


	June 30,			December 31,
	2011			2010
Derivative assets:
Natural gas — collars	$	107,258		$	155,159
— collars — discontinued operations		—			8,195
— swaps		4,014			—
Crude oil — collars		(15,830	)		—
— call options		(43,675	)		(31,904	)
NGL — swaps		13,750			—

	$	65,517		$	131,450


Derivative liabilities:
Natural gas — collars	$	3,079		$	27,032
— basis swaps		—			(352	)
— swaps		169			—
Crude oil — collars		—			(12,051	)
— call options		(7,675	)		(28,393	)
NGL — swaps		—			—

	$	(4,427	)	$	(13,764	)

The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our accompanying consolidated balance sheets (in thousands):


	June 30, 2011								December 31, 2010
	Assets		(Liabilities)						Assets		(Liabilities)
						Net								Net
	Carrying		Carrying			Carrying			Carrying		Carrying			Carrying
	Value		Value			Value			Value		Value			Value
Derivatives that qualify for cash flow hedge accounting:
Swaps ⁽¹⁾	$	4,184	$	—		$	4,184		$	—	$	—		$	—
Collars⁽¹⁾		103,907		—			103,907			164,933		—			164,933
Collars ⁽¹⁾ — discontinued operations		—		—			—			8,195		—			8,195

	$	108,091	$	—		$	108,091		$	173,128	$	—		$	173,128


Derivatives that do not qualify for hedge accounting:
Swaps ⁽¹⁾	$	13,750	$	—		$	13,750		$	—	$	—		$	—
Collars⁽¹⁾		6,430		(15,830	)		(9,400	)		17,259		(12,052	)		5,207
Call options⁽¹⁾		—		(51,351	)		(51,351	)		—		(60,297	)		(60,297	)
Basis swaps⁽¹⁾		—		—			—			—		(352	)		(352	)

	$	20,180	$	(67,181	)	$	(47,001	)	$	17,259	$	(72,701	)	$	(55,442	)


⁽¹⁾		Included in unrealized derivative gain or loss in the accompanying consolidated balance sheets.

The effects of our cash flow hedges (or those derivatives that qualify for hedge accounting) on accumulated other comprehensive income (loss) included in the accompanying consolidated balance sheets are summarized below (in thousands):


	Three Months Ended June 30,												Six Months Ended June 30,
							Realized Gain (Loss)												Realized Gain (Loss)
	Change in Hedge						Reclassified from OCI						Change in Hedge						Reclassified from OCI
	Derivative Fair Value						into Revenue ^(a)						Derivative Fair Value						into Revenue ^(a)
	2011			2010			2011			2010			2011			2010			2011			2010
Swaps	$	4,655		$	—		$	—		$	—		$	2,115		$	—		$	—		$	—
Collars		23,223			(6,887	)		24,285			18,340			22,424			77,930			53,902			19,555
Collars — discontinued operations		—			19			—			—			412			13			8,607			—
Income taxes		(10,454	)		2,611			(9,107	)		(6,969	)		(7,414	)		(29,618	)		(23,441	)		(7,431	)

	$	17,424		$	(4,257	)	$	15,178		$	11,371		$	17,537		$	48,325		$	39,068		$	12,124


^(a)		For realized gains upon contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGL and oil sales. For realized losses upon contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGL and oil sales.

The effects of our non-hedge derivatives (or those derivatives that do not qualify for hedge accounting) and the ineffective portion of our hedge derivatives included in the accompanying consolidated statements of operations are summarized below (in thousands):


	Three Months Ended June 30,
	Gain (Loss) Recognized in				Gain Recognized in Income				Derivative Fair Value
	Income (Non-hedge Derivatives)				(Ineffective Portion)				(Loss) Income
	2011		2010		2011		2010		2011		2010
Swaps	$	15,613	$	—	$	—	$	—	$	15,613	$	—
Collars		6,452		1,483		7,510		265		13,962		1,748
Call options		23,464		—		—		—		23,464		—
Basis swaps		—		4,798		—		—		—		4,798

Total	$	45,529	$	6,281	$	7,510	$	265	$	53,039	$	6,546


	Six Months Ended June 30,
	Gain (Loss) Recognized in					Gain Recognized in Income					Derivative Fair Value
	Income (Non-hedge Derivatives)					(Ineffective Portion)					(Loss) Income
	2011			2010		2011		2010			2011			2010
Swaps	$	13,750		$	—	$	—	$	—		$	13,750		$	—
Collars		(1,135	)		48,438		9,024		(341	)		7,889			48,097
Call options		(9,391	)		—		—		—			(9,391	)		—
Basis swaps		(43	)		782		—		—			(43	)		782

Total	$	3,181		$	49,220	$	9,024	$	(341	)	$	12,205		$	48,879

(13) FAIR VALUE MEASUREMENTS

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. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes 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. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish 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. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

	•		Level 1 — Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

	•		Level 2 — Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

	•		Level 3 — Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities 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.

Fair Values-Recurring

We use a market approach for our fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):


	Fair Value Measurements at June 30, 2011 Using:
	Quoted Prices in		Significant					Total
	Active Markets		Other			Significant		Carrying
	for Identical		Observable			Unobservable		Value as of
	Assets		Inputs			Inputs		June 30,
	(Level 1)		(Level 2)			(Level 3)		2011
Trading securities held in our deferred compensation plans	$	52,129	$	—		$	—	$	52,129
Derivatives – swaps		—		17,934			—		17,934
– collars		—		94,507			—		94,507
– call options		—		(51,351	)		—		(51,351	)

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using June 30, 2011 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in our accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends and mark-to-market gains/losses are included in deferred compensation plan expense in our consolidated statements of operations. For the three months ended June 30, 2011, interest and dividends were $60,000 and mark-to-market was a gain of $5,000. For the three months ended June 30, 2010, interest and dividends were $39,000 and mark-to-market was a gain of $3.2 million. For the six months ended June 30, 2011, interest and dividends were $95,000 and mark-to-market was a gain of $1.3 million. For the six months ended June 30, 2010 interest and dividends were $71,000 and mark-to-market was a gain of $3.8 million. For additional information on the accounting for our deferred compensation plan, see Note 14.

Fair Values-Nonrecurring

We review our long-lived assets to be held and used, including proved natural gas and oil properties, whenever events or circumstances indicate the carrying value of those assets may not be recoverable. Several long-lived assets held for use were evaluated for impairment during 2010 due to reductions in estimated reserves and natural gas prices. The fair value of our onshore Gulf Coast assets in 2010 was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. Our projected undiscounted cash flows associated with these assets was less than their carrying value and therefore, we recorded an impairment of $6.5 million in 2010 related to our onshore Gulf Coast proved properties.

The following table presents the value of these assets measured at fair value on a nonrecurring basis (in thousands):


	Six Months Ended June 30,
	2011				2010
					Fair
	Fair Value		Impairment		Value		Impairment
Natural gas and oil properties	$	—	$	—	$	16,075	$	6,505

Fair Values-Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of June 30, 2011 and December 31, 2010 (in thousands):


	June 30, 2011						December 31, 2010
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
Assets:
Commodity swaps, collars, call options and basis swaps	$	65,517		$	65,517		$	123,255		$	123,255
Commodity collars – discontinued operations		—			—			8,195			8,195
Marketable securities^(a)		52,129			52,129			47,794			47,794

Liabilities:
Commodity swaps, collars, call options and basis swaps		(4,427	)		(4,427	)		(13,764	)		(13,764	)
Bank credit facility ^(b)		—			—			(274,000	)		(274,000	)
6.375% senior subordinated notes due 2015 ^(b)		—			—			(150,000	)		(153,000	)
7.5% senior subordinated notes due 2016 ^(b)		—			—			(249,683	)		(259,375	)
7.5% senior subordinated notes due 2017 ^(b)		(250,000	)		(265,625	)		(250,000	)		(263,438	)
7.25% senior subordinated notes due 2018 ^(b)		(250,000	)		(265,000	)		(250,000	)		(263,750	)
8.0% senior subordinated notes due 2019 ^(b)		(287,398	)		(325,500	)		(286,853	)		(326,625	)
6.75% senior subordinated notes due 2020 ^(b)		(500,000	)		(517,500	)		(500,000	)		(515,625	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(491,250	)		—			—


^(a)		Marketable securities are held in our deferred compensation plans.

^(b)		The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes.

Concentration of Credit Risk

Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as deemed necessary to limit risk of loss. Our allowance for uncollectible receivables was $3.8 million at June 30, 2011 and $5.0 million at December 31, 2010. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. As of June 30, 2011, these contracts consist of swaps, collars and call options. This exposure is diversified among major investment grade financial institutions and we have master netting agreements with the counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative counterparties include ten financial institutions, of which all but one are secured lenders in our bank credit facility. Macquarie Bank Limited is the only counterparty not in our bank group. At June 30, 2011 our net derivative receivable includes a receivable from Macquarie Bank Limited of $6.9 million. Our natural gas and oil properties provide collateral under our credit facility and our derivative exposure. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.

(14)

EMPLOYEE BENEFIT AND EQUITY PLANS

We have two active equity-based stock compensation plans. Under these plans, incentive and non-qualified stock options, SARs, restricted stock, restricted stock units, phantom stock and various other awards may be issued to employees and directors pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors.

Equity Awards – SARs/Stock Options

All awards granted have been issued at prevailing market prices at the time of the grant. Information with respect to stock option/SARs activity is summarized below:


				Weighted
				Average
	Shares			Exercise Price
Outstanding at December 31, 2010		6,461,839		$	37.20
Granted		841,620			51.15
Exercised		(1,507,274	)		27.00
Expired/forfeited		(193,940	)		54.31

Outstanding at June 30, 2011		5,602,245		$	41.44

The weighted average fair value of a SAR to purchase one share of common stock granted during 2011 was $18.21. The fair value of each SAR granted during 2011 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 1.4%; dividend yield of 0.3%; expected volatility of 47% and an expected life of 3.6 years. Of the 5.6 million stock option/SARs outstanding at June 30, 2011, 658,000 are stock options and 4.9 million are SARs.

Equity Awards-Restricted Stock Units

Beginning in first quarter 2011, the compensation committee began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us. Net shares will be issued to employees as the restricted stock units vest. A summary of the non-vested restricted stock unit awards at June 30, 2011 is presented below:


				Weighted
				Average
				Grant Date
	Shares			Fair Value
Non-vested restricted stock units outstanding at December 31, 2010		—		$	—
Granted		329,399			49.46
Vested		(36,995	)		49.22
Expired/forfeited		(8,472	)		49.18

Non-vested restricted stock units outstanding at June 30, 2011		283,932		$	49.50

Liability Awards-Restricted Stock

These restricted stock shares are placed into our deferred compensation plan when granted. During the first six months of 2011, 334,000 shares of restricted stock (or non-vested shares) were issued to certain employees at an average price of $51.10 with a three-year vesting period and 15,500 shares were granted to directors at an average price of $52.35 with immediate vesting. In the first six months of 2010, we issued 385,000 shares of restricted stock as compensation to employees at an average price of $45.97 with a three-year vesting period and 21,000 shares were granted to our directors at an average price of $45.51 with immediate vesting. All restricted stock awards held in our deferred compensation plans are classified as a liability award and remeasured at fair value each reporting period. This mark-to-market is included in deferred compensation plan expense in our accompanying consolidated statements of operations (see additional discussion below). All awards granted have been issued at prevailing market prices at the time of the grant and the vesting of these shares is based upon an employee’s continued employment with us.

A summary of the status of our non-vested restricted stock outstanding at June 30, 2011 is presented below:


				Weighted
				Average Grant
	Shares			Date Fair Value
Non-vested restricted stock outstanding at December 31, 2010		582,751		$	44.81
Granted		349,480			51.16
Vested		(213,929	)		46.83
Forfeited		(21,176	)		44.87

Non-vested restricted stock outstanding at June 30, 2011		697,126		$	47.37

Deferred Compensation Plan

Our 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 grantor 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. Our stock granted and held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals either in cash or in Range stock. The liability associated with the vested portion of Range stock is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements 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 in the accompanying consolidated balance sheets. Changes in the market value of the marketable securities are charged or credited to deferred compensation plan expense each quarter. The deferred compensation liability included in our consolidated balance sheets reflects the vested market value of the marketable securities and Range common stock held in the Rabbi Trust. We recorded non-cash, mark-to-market income related to our deferred compensation plan of $5.8 million in the three months ended June 30, 2011 compared to income of $14.1 million in the same period of 2010. We recorded non-cash mark-to-market expense related to our deferred compensation plan of $24.9 million in the six months ended June 30, 2011 compared to income of $19.8 million in the same period of 2010.

(15) SUPPLEMENTAL CASH FLOW INFORMATION


	Six Months Ended
	June 30,
	2011		2010
	(in thousands)
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	12,717	$	864
Unproved property purchased with stock^(a)	$	—	$	20,000
Net cash provided from operating activities included:
Interest paid	$	68,002	$	58,457
Income taxes paid (refunded)	$	308	$	(684	)


^(a)		Six months ended June 30, 2010 included shares that were issued in January 2010 while the value was accrued and included in costs incurred for the year ended December 31, 2009.

(16) COMMITMENTS AND CONTINGENCIES

Litigation

We are involved in various legal actions, claims and other regulatory proceedings 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. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income or loss in the period in which the ruling occurs. We provide accruals for litigation and claims if we determine that the loss is probable and the amount can be reasonably estimated.

Transportation Contracts

As of June 30, 2011, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):


	Transportation
	Commitments
2011 (remaining)	$	45,315
2012		90,361
2013		89,768
2014		88,826
2015		86,361
Thereafter		503,940

	$	904,571


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


	June 30,			December 31,
	2011			2010
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	5,326,056		$	4,742,248
Unproved properties		673,609			648,143

Total		5,999,665			5,390,391
Accumulated depreciation, depletion and amortization		(1,447,300	)		(1,306,378	)

Net capitalized costs	$	4,552,365		$	4,084,013


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

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


	Six Months		Year
	Ended		Ended
	June 30,		December 31,
	2011		2010
	(in thousands)
Acquisitions:
Unproved leasehold	$	—	$	3,697
Proved properties		—		130,767
Asset retirement obligations		—		556
Acreage purchases		67,140		151,572
Development		476,702		727,720
Exploration:
Drilling		68,936		50,433
Expense		36,513		56,298
Stock-based compensation expense		2,266		4,209
Gas gathering facilities:
Development		11,540		19,627

Subtotal		663,097		1,144,879
Asset retirement obligations		12,716		(6,370	)

Total costs incurred – continuing operations		675,813		1,138,509
Discontinued operations		3,502		73,369

Total costs incurred	$	679,315	$	1,211,878


^(a)		Includes costs incurred whether capitalized or expensed and include our Barnett operations.


(19)		OFFICE CLOSING AND EXIT ACTIVITIES

In February 2010, we entered into an agreement to sell our natural gas properties in Ohio. We closed approximately 90% of the sale in March 2010 and closed the remainder of the sale in June 2010. The first quarter 2010 includes $5.1 million accrued severance costs, which is reflected in termination costs in the accompanying consolidated statements of operations. As part of their severance agreement, our Ohio employees’ vesting of SARs and restricted stock grants was accelerated, increasing termination costs for stock compensation expense in first quarter 2010 by approximately $2.8 million.

The following table details our exit activities, which are included in accrued liabilities in the accompanying consolidated balance sheets as of June 30, 2011 and December 31, 2010 (in thousands):


	Six Months			Year
	Ended			Ended
	June 30,			December 31,
	2011			2010
	(in thousands)
Balance at beginning of period	$	1,092		$	1,568
Accrued one-time termination costs		—			5,138
Office lease		(117	)		514
Payments		(742	)		(6,128	)

Balance at end of period	$	233		$	1,092

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

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. For additional risk factors affecting our business, see Item 1A. Risk Factors as filed with our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC on March 1, 2011.

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. These policies and estimates are described in our Current Report on Form 8-K for the year ended December 31, 2010 filed with the SEC on May 6, 2011. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: accounting for natural gas, NGL and oil revenue, natural gas and oil properties, stock-based compensation, derivative financial instruments, asset retirement obligations and deferred income taxes.

Market Conditions

Prices for various quantities of natural gas, natural gas liquids (“NGLs”) and oil that we produce significantly impact our revenues and cash flows. Commodity prices can fluctuate widely. The following table lists average New York Mercantile Exchange (“NYMEX”) prices for natural gas and oil for the three months and six months ended June 30, 2011 and 2010.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Average NYMEX prices^(a)
Natural gas (per mcf)	$	4.36	$	4.08	$	4.25	$	4.71
Oil (per bbl)		102.33		77.71		98.77		78.28


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

Consolidated Results of Operations

Overview

We are an independent natural gas and oil company engaged in the exploration, development and acquisition of natural gas and oil properties, mostly in the Appalachia and Southwest regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to economically find, develop, acquire and produce natural gas and oil reserves. We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital program. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located in Fort Worth, Texas. Discontinued operations consist of our Barnett Shale properties which were sold in second quarter 2011. Unless otherwise indicated, the information included herein relates to our continuing operations.

During the first six months of 2011, we achieved the following financial and operating results:

	•		achieved 29% year-over-year production growth;

	•		daily production now exceeds 455.0 mmcfe per day;

	•		natural gas, NGL and oil sales increased 34% from six months of 2010;

	•		reduced our DD&A rate 12% from six months 2010;

	•		year-over-year direct operating expense per mcfe increased 1% while production and ad valorem tax expense per mcfe declined 11% and general and administrative expense per mcfe declined 11%;

	•		sold substantially all of our Barnett Shale properties for gross proceeds of $877.0 million, including assumed hedges;

	•		entered into additional commodity derivative contracts for 2011, 2012 and 2013;

	•		renewed our bank credit facility with a borrowing base of $2.0 billion;

	•		issued $500.0 million of new 5.75% senior subordinated notes, at par; and

	•		used the proceeds from the issuance of $500.0 million of new 5.75% senior subordinated notes to retire all $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 and all $250.0 million principal amount of our 7.5% senior subordinated notes due 2016.

Second Quarter Highlights

Total revenues increased $115.5 million, or 60% for second quarter 2011 over the same period of 2010. The increase includes a $83.5 million increase in natural gas, NGL and oil sales and an increase in derivative fair value income of $46.5 million partially offset by lower gain on sale of assets of $11.8 million. Natural gas, NGL and oil sales vary due to changes in volumes of production sold and realized commodity prices. Realized prices increased from the same period of the prior year, along with an increase in production, including a 73% increase in NGL production primarily due to increased liquids-rich production in our Appalachia area. For second quarter 2011, production increased 33% from the same period of the prior year while realized prices (including all derivative settlements) increased 5%. In second quarter 2011, we completed the sale of most of our Barnett Shale properties for cash gross proceeds of $877.0 million, including assumed hedges, resulting in a pretax gain of $3.8 million. See also Note 4 and 5 for specific information on the sale of these assets including their treatment as discontinued operations.

In May 2011, we issued, at par, $500.0 million of 5.75% senior subordinated notes due 2021. The net proceeds were used to repurchase $150.0 million of our 6.375% senior subordinated notes due 2015 (“6.375% Notes”) and $250.0 million of our 7.5% senior subordinated notes due 2016 (“7.5% Notes”) and for general working capital purposes. On May 24, 2011, we commenced cash tender offers to purchase the entire outstanding principal amount of each of the 6.375% Notes and the 7.5% Notes. Upon expiration of the tender offers in May 2011, we accepted for purchase $108.9 million in principal of the 6.375% Notes at 102.375% of par and $198.8 million in principal of the 7.5% Notes at 104.0% of par. We called the remaining 6.375% Notes and 7.5% Notes, repurchasing all of the remaining outstanding 6.375% Notes at 102.125% of par on June 24, 2011 and repurchased all of the remaining outstanding 7.5% Notes at 103.75% of par on June 24, 2011. During second quarter 2011, we recognized a $18.6 million loss on extinguishment of debt in the accompanying statements of operations.

We continue to believe natural gas, NGL and oil prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new regulations, new technology, the level of natural gas and oil production in North America and worldwide political conditions in natural gas and oil producing regions. Although we have entered into derivative contracts covering a portion of our production volumes for 2011, 2012 and 2013, a sustained lower price environment would result in lower realized prices for unprotected volumes and reduce the prices we can enter into derivative contracts for additional volumes in the future.

Natural Gas, NGL and Oil Sales Production and Realized Price Calculation

Our natural gas, NGL and oil sales vary from quarter to quarter as a result of changes in realized commodity prices and volumes of production sold. Hedges included in natural gas, NGL and oil sales reflect settlements on those derivatives that qualify for hedge accounting. The cash settlement of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the accompanying consolidated statements of operations. The following table summarizes the primary components of natural gas, NGL and oil sales for the three months and six months ended June 30, 2011 and 2010 (in thousands):


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2011		2010		Change			%			2011		2010		Change			%
Gas wellhead	$	123,300	$	95,257	$	28,043			29	%	$	229,583	$	218,527	$	11,056			5	%
Gas hedges realized		24,285		18,317		5,968			33	%		53,901		19,532		34,369			176	%

Total gas sales		147,585		113,574		34,011			30	%		283,484		238,059		45,425			19	%


NGL’s		62,598		27,402		35,196			128	%		117,073		55,426		61,647			111	%


Oil wellhead		46,504		32,154		14,350			45	%		83,011		67,318		15,693			23	%
Oil hedges realized		—		23		(23	)		100	%		—		23		(23	)		100	%

Total oil sales		46,504		32,177		14,327			45	%		83,011		67,341		15,760			23	%


Combined wellhead		232,402		154,813		77,589			50	%		429,667		341,271		88,396			26	%
Combined hedges realized		24,285		18,340		5,945			32	%		53,901		19,555		34,346			176	%

Total natural gas, NGL and oil sales	$	256,687	$	173,153	$	83,534			48	%	$	483,568	$	360,826	$	122,742			34	%

Our production continues to grow through continued drilling success as we place new wells into production, partially offset by the natural decline of our wells and asset sales. For second quarter 2011, total production volumes, when compared to the same period of the prior year, increased 48% in our Appalachia area and 3% in our Southwest area. For second quarter 2011, NGL production increased 73% from the same period of the prior year primarily due to increased liquids-rich gas production in our Appalachia area along with an increase in processing capacity in the region. For the six months ended June 30, 2011, our production volumes as compared to the same period of the prior year, increased 44% in our Appalachia area and increased 2% in our Southwest area. Our production for the three months and six months ended June 30, 2011 and 2010 is shown below:


	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2011		2010		Change		%			2011		2010		Change			%
Production^(a):
Natural gas (mcf)		32,811,471		25,426,232		7,385,239		29	%		62,616,994		49,798,399		12,818,595			26	%
NGLs (bbls)		1,236,502		715,725		520,777		73	%		2,368,067		1,339,199		1,028,868			77	%
Crude oil (bbls)		502,962		474,557		28,405		6	%		939,094		979,658		(40,564	)		(4	%)
Total (mcfe)^(b)		43,248,255		32,567,924		10,680,331		33	%		82,459,960		63,711,541		18,748,419			29	%

Average daily production^(a):
Natural gas (mcf)		360,566		279,409		81,157		29	%		345,950		275,129		70,821			26	%
NGLs (bbls)		13,588		7,865		5,723		73	%		13,083		7,399		5,684			77	%
Crude oil (bbls)		5,527		5,215		312		6	%		5,188		5,412		(224	)		(4	%)
Total (mcfe)^(b)		475,256		357,889		117,367		33	%		455,580		351,997		103,583			29	%


^(a)		Represents volumes sold regardless of when produced.

^(b)		NGLs and oil are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

Our average realized price (including all derivative settlements) received was $5.91 per mcfe in second quarter 2011 compared to $5.65 per mcfe in the same period of the prior year. Our average realized price (including all derivative settlements) received was $5.84 per mcfe in the six months ended June 30, 2011 compared to $5.77 per mcfe in the same period of the prior year. Our average realized price calculation (including all derivative settlements) includes all cash settlements for derivatives, whether or not they qualify for hedge accounting. Average price calculations for the three months and six months ended June 30, 2011 and 2010 are shown below:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
Average sales prices (wellhead):
Natural gas (per mcf)	$	3.76	$	3.75	$	3.67	$	4.39
NGLs (per bbl)		50.62		38.29		49.44		41.39
Crude oil (per bbl)		92.46		67.76		88.40		68.72
Total (per mcfe)^(a)		5.37		4.75		5.21		5.36

Average realized price (including derivatives that qualify for hedge accounting):
Natural gas (per mcf)	$	4.50	$	4.47	$	4.53	$	4.78
NGLs (per bbl)		50.62		38.29		49.44		41.39
Crude oil (per bbl)		92.46		67.80		88.39		68.74
Total (per mcfe)^(a)		5.94		5.32		5.86		5.66

Average realized price (including all derivative settlements):
Natural gas (per mcf)	$	4.65	$	4.89	$	4.62	$	4.91
NGLs (per bbl)		50.62		38.29		49.44		41.39
Crude oil (per bbl)		80.34		67.81		79.86		68.72
Total (per mcfe)^(a)		5.91		5.65		5.84		5.77


^(a)		NGLs and oil are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil and natural gas prices.

Derivative fair value income was $53.0 million in second quarter 2011 compared to $6.5 million in the same period of 2010. Derivative fair value income was $12.2 million in the six months ended June 30, 2011 compared to $48.9 million in the same period of 2010. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income in the accompanying consolidated statements of operations. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from non-hedge derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying consolidated balance sheets. Hedge ineffectiveness, also included in this statement of operations category, is associated with our hedging contracts that qualify for hedge accounting.

The following table presents information about the components of derivative fair value income for the three months and six months ended June 30, 2011 and 2010 (in thousands):


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Hedge ineffectiveness — realized^(c)	$	1,576		$	5		$	2,522		$	(352	)
— unrealized^(a)		5,934			260			6,502			11
Change in fair value of derivatives that do not qualify for hedge accounting^(a)		48,139			(4,409	)		8,103			42,169
Realized gain on settlements — gas^(b)(c)		3,484			10,690			3,090			7,051
Realized loss on settlements — oil^(b)(c)		(6,094	)		—			(8,012	)		—

Derivative fair value income	$	53,039		$	6,546		$	12,205		$	48,879


^(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 (average realized price including all derivative settlements).

(Loss) gain on the sale of assets for second quarter 2011 decreased $11.8 million from the same period of the prior year. In the three months ended June 30, 2011, we recorded a loss of $1.7 million related to the sale of certain derivatives included with the sale of our Barnett properties. In the three months ended June 30, 2010, we closed the remainder of the sale of our properties in Ohio and recorded a gain of $10.4 million. For the six months ended June 30, 2010, we recorded a gain of $77.4 million from the sale of our Ohio properties and received proceeds of $323.0 million.

Other income (loss) for second quarter 2011 was a loss of $435,000 compared to a gain of $637,000 in the same period of 2010. Second quarter 2011 includes loss from equity method investments of $1.0 million. The second quarter of 2010 includes income from equity method investments of $636,000. Other income (loss) for the six months ended June 30, 2011 increased from a loss of $938,000 in 2010 to income of $642,000 in 2011. The six months ended June 30, 2011 includes various lawsuit proceeds and refunds partially offset by a loss from equity method investments of $759,000. The six months ended June 30, 2010 includes a loss from equity method investments of $985,000.

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about these expenses on a per mcfe basis for the three months and the six months ended June 30, 2011 and 2010:


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2011		2010		Change			%			2011		2010		Change			%
Direct operating expense	$	0.66	$	0.65	$	0.01			2	%	$	0.69	$	0.68	$	0.01			1	%
Production and ad valorem tax expense		0.17		0.17		—			—	%		0.17		0.19		(0.02	)		(11	%)
General and administrative expense		0.90		1.10		(0.20	)		(18	%)		0.89		1.00		(0.11	)		(11	%)
Interest expense		0.73		0.65		0.08			12	%		0.68		0.66		0.02			3	%
Depletion, depreciation and amortization expense		1.81		2.08		(0.27	)		(13	%)		1.83		2.08		(0.25	)		(12	%)

Direct operating expense increased $7.3 million in second quarter 2011 to $28.5 million. We experience increases in operating expenses as we add new wells and maintain production from existing properties. We incurred $596,000 ($0.01 per mcfe) of workover costs in second quarter 2011 versus $1.0 million ($0.03 per mcfe) in 2010. On a per mcfe basis, direct operating expenses for second quarter 2011 increased $0.01, or 2%, from the same period of 2010 with the increase primarily due to higher equipment rental ($0.03) and higher water hauling and disposal costs ($0.04 per mcfe) somewhat offset by lower workover costs ($0.02 per mcfe) and lower well services costs ($0.03 per mcfe).

Direct operating expense increased $14.2 million in the first six months 2011 to $57.2 million. We incurred $987,000 ($0.01 per mcfe) of workover costs in the first six months of 2011 compared to $1.8 million ($0.03 per mcfe) in the same period of 2010. On a per mcfe basis, direct operating expense increased $0.01 or 1% from the same period of the prior year with the increase consisting primarily of higher water disposal costs ($0.05 per mcfe) and higher overall well service costs somewhat offset by lower workover costs ($0.02 per mcfe) and the impact of the sale of certain higher operating cost assets during 2010. In the future, we expect to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operating costs relative to our other operating areas. Stock-based compensation included in this category represents amortization of restricted stock grants and expense related to SAR grants.

The following table summarizes direct operating expenses per mcfe for the three months and six months ended June 30, 2011 and 2010:


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2011		2010		Change			%			2011		2010		Change			%
Lease operating expense	$	0.64	$	0.60	$	0.04			7	%	$	0.67	$	0.64	$	0.03			5	%
Workovers		0.01		0.03		(0.02	)		(67	%)		0.01		0.03		(0.02	)		(67	%)
Stock-based compensation (non-cash)		0.01		0.02		(0.01	)		(50	%)		0.01		0.01		—			—	%

Total direct operating expenses	$	0.66	$	0.65	$	0.01			2	%	$	0.69	$	0.68	$	0.01			1	%

Production and ad valorem taxes are paid based on market prices and not hedged prices. For second quarter 2011, these taxes increased $1.9 million or 33% from the same period of the prior year with higher prices partially offset by an increase in production volumes not subject to production taxes. On a per mcfe basis, production and ad valorem taxes per mcfe remained the same at $0.17 for the three months ended June 2011 and 2010. For the first six months of 2011, these taxes increased $2.2 million or 18% from the same period of the prior year due to a decrease in the number of wells receiving high cost tax credits and higher NGL production volumes subject to production taxes which was partially offset by an increase in production volumes not subject to production taxes and lower prices. On a per mcfe basis, production and ad valorem taxes decreased to $0.17 in the first six months of 2011 compared to $0.19 in the same period of 2010.

General and administrative expense for second quarter 2011 increased $3.3 million or 9% from the same period of the prior year due primarily to higher community relations costs ($1.1 million), higher stock-based compensation ($729,000), higher legal costs ($1.0 million) and higher office expenses, including information technology. General and administrative expense for the first six months of 2011 increased $9.1 million or 14% from the same period of the prior year primarily due to higher community relations costs ($2.5 million), higher stock-based compensation ($413,000), higher salaries and benefits ($2.3 million), higher legal fees ($2.7 million) and higher office expenses, including information technology. Stock-based compensation included in this category represents amortization of restricted stock grants and expense related to SAR grants. The following table summarizes general and administrative expenses per mcfe for the three months and the six months ended June 30, 2011 and 2010:


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2011		2010		Change			%			2011		2010		Change			%
General and administrative	$	0.63	$	0.77	$	(0.14	)		(18	%)	$	0.66	$	0.71	$	(0.05	)		(7	%)
Stock-based compensation (non-cash)		0.27		0.33		(0.06	)		(18	%)		0.23		0.29		(0.06	)		(21	%)

Total general and administrative expenses	$	0.90	$	1.10	$	(0.20	)		(18	%)	$	0.89	$	1.00	$	(0.11	)		(11	%)

Interest expense for second quarter 2011 increased $10.1 million from the same period of the prior year due to the refinancing of certain debt from floating to higher fixed rates and higher overall debt balances. In May 2011, we issued $500.0 million of new 5.75% senior subordinated notes due 2021, which added $2.9 million of interest costs in second quarter 2011. The proceeds from the issuance were used to retire our 6.375% senior subordinated notes due 2015 and retire our 7.5% senior subordinated notes due 2016 and for general corporate purposes, in order to better match the maturities of our debt with the life of our properties. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020, which added $8.4 million of interest costs in second quarter 2011. The proceeds from the issuance were used to retire our 7.375% senior subordinated notes due 2013 and to lower our floating interest rate bank debt, which better matches the maturities of our debt with the life of our properties and gives us greater liquidity for the near term. Average debt outstanding on the bank credit facility for second quarter 2011 was $171.5 million compared to $421.1 million for the same period of the prior year and the weighted average interest rate was 2.0% in second quarter 2011 compared to 2.2% in the same period of the prior year.

Interest expense for the six months increased $14.0 million from the same period of the prior year due to the refinancing of certain debt from floating to higher fixed rates and higher overall debt balances. In May 2011, we issued $500.0 million of 5.75% senior subordinated notes due 2021, which added $2.9 million of interest costs in the first six months of 2011. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020, which added $16.9 million of interest costs in the first six months of 2011. Average debt outstanding on the credit facility for the first six months 2011 was $296.3 million compared to $390.4 million for the same period of the prior year and the weighted average interest rate was 2.2% in both the six months periods ending June 30, 2011 and 2010.

Depletion, depreciation and amortization (“DD&A”) increased $10.5 million, or 15%, to $78.3 million in second quarter 2011. The increase was due to a 33% increase in production partially offset by a 12% decrease in depletion rates. On a per mcfe basis, DD&A decreased from $2.08 in second quarter 2010 to $1.81 in second quarter 2011. In the first six months of 2011, DD&A increased $17.9 million with a 29% increase in production partially offset by a 10% decrease in depletion rates. Depletion rates are declining due to our lower finding and development costs and the mix of our production. The following table summarizes DD&A expense per mcfe for the three months and the six months ended June 30, 2011 and 2010:


	Three Months Ended										Six Months Ended
	June 30,										June 30,
	2011		2010		Change			%			2011		2010		Change			%
Depletion and amortization	$	1.70	$	1.93	$	(0.23	)		(12	%)	$	1.71	$	1.91	$	(0.20	)		(10	%)
Depreciation		0.08		0.11		(0.03	)		(27	%)		0.09		0.13		(0.04	)		(31	%)
Accretion and other		0.03		0.04		(0.01	)		(25	%)		0.03		0.04		(0.01	)		(25	%)

Total DD&A expense	$	1.81	$	2.08	$	(0.27	)		(13	%)	$	1.83	$	2.08	$	(0.25	)		(12	%)

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties, termination costs, deferred compensation plan expenses and impairment of proved properties. In the three months ended June 30, 2011 and 2010, stock-based compensation represents the amortization of restricted stock grants, restricted stock units and expenses related to SAR grants. In second quarter 2011, stock-based compensation is a component of direct operating expense ($643,000), exploration expense ($937,000) and general and administrative expense ($11.5 million) for a total of $13.4 million. In second quarter 2010, stock-based compensation was a component of direct operating expense ($563,000), exploration expense ($1.1 million) and general and administrative expense ($10.7 million) for a total of $12.7 million. In the six months ended June 30, 2011, stock-based compensation is a component of direct operating expense ($953,000), exploration expense ($2.3 million) and general and administrative expense ($19.0 million) for a total of $22.9 million. In the six months ended June 30, 2010, stock-based compensation is a component of direct operating expense ($925,000), exploration expense ($2.2 million) and general and administrative expense ($18.6 million) for a total of $22.4 million.

Exploration expense decreased $2.8 million in second quarter 2011 and increased $10.2 million in the first six months of 2011 from the same periods of the prior year. The three months ended June 30, 2011 includes higher seismic costs more than offset by lower delay rental costs. The six months ended June 30, 2011 includes higher seismic and personnel costs partially offset by lower delay rental costs. The delay rental payments, or costs to defer the commencement of drilling, are primarily attributed to our Marcellus Shale operations. The following table details our exploration-related expenses for the three months and six months ended June 30, 2011 and 2010 (in thousands):


	Three Months Ended											Six Months Ended
	June 30,											June 30,
	2011			2010		Change			%			2011		2010		Change			%
Dry hole expense	$	(3	)	$	—	$	(3	)		—	%	$	7	$	—	$	7			—	%
Seismic		4,365			833		3,532			424	%		17,537		8,046		9,491			118	%
Personnel expense		3,150			2,910		240			8	%		7,176		5,640		1,536			27	%
Stock-based compensation expense		937			1,069		(132	)		(12	%)		2,266		2,205		61			3	%
Delay rentals and other		3,143			9,608		(6,465	)		(67	%)		11,793		12,668		(875	)		(7	%)

Total exploration expense	$	11,592		$	14,420	$	(2,828	)		(20	%)	$	38,779	$	28,559	$	10,220			36	%

Abandonment and impairment of unproved properties expense was $18.9 million during the three months ended June 30, 2011 compared to $9.7 million during the same period of 2010. Abandonment and impairment of unproved properties was $35.4 million in the six months ended June 30, 2011 compared to $16.3 million in the same period of the prior year. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. The increase from the prior year is primarily due to increasing expirations in our Marcellus Shale area.

Termination costs in the first six months of 2010 includes severance costs of $5.1 million related to the sale of our properties in Ohio and $2.8 million of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Ohio personnel.

Deferred compensation plan expense was income of $5.8 million in second quarter 2011 compared to income of $14.1 million in the same period of the prior year. This non-cash expense relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in the deferred compensation plan. Our deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense in the accompanying

statements of operations. Our stock price decreased from $58.46 at March 31, 2011 to $55.50 at June 30, 2011. During the same period in the prior year, our stock price decreased from $46.87 at March 31, 2010 to $40.15 at June 30, 2010. Deferred compensation plan expense was $24.9 million in the six months ended June 30, 2011 compared to income of $19.8 million in the same period of the prior year. Our stock price increased from $44.98 at December 31, 2010 to $55.50 at June 30, 2011. During the same six month period of the prior year our stock price decreased from $49.85 at December 31, 2009 to $40.15 at June 30, 2010.

Loss on extinguishment of debt for the second quarter and the six months ended June 30, 2011 was $18.6 million. In May and June 2011, we purchased or redeemed our 6.375% senior subordinated notes due 2015 at a price equal to 102.31% and we purchased or redeemed our 7.5% senior subordinated notes due 2016 at a price equal to 103.95%. We recorded a loss on extinguishment of debt of $18.6 million which includes a call premium and other consideration of $13.3 million and expensing of related deferred financing costs on the repurchased debt.

Impairment of proved properties in the first six months of 2010 of $6.5 million was recognized due to declining gas prices and is related to a portion of our onshore Gulf Coast properties. Our estimated fair value of producing properties is generally calculated as the discounted present value of future net cash flows. Our estimates of cash flow were based on the latest available proved reserves and production information and management’s estimates of future product prices and costs, based on available information such as forward strip prices, at the time of the impairment.

Income tax expense for second quarter 2011 increased to $32.7 million from $11.8 million in second quarter 2010, reflecting a 167% increase in continuing income from operations before taxes compared to the same period of 2010. Second quarter 2011 provided for tax expense at an effective rate of 41.6% compared to tax expense at an effective rate of 40.0% in the same period of 2010. Income tax expense for the first six months 2011 decreased to $12.8 million from $60.8 million in the first six months 2010, reflecting an 84% decrease in continuing income from operations before taxes. The first six months 2011 provided for tax expense at an effective rate of 50.9% compared to an effective tax rate of 38.9% in the same period of 2010. We expect our effective tax rate to be approximately 40% for the remainder of 2011. Our overall effective tax rate is higher than the statutory rate of 35% due to state income taxes, valuation allowances and other permanent differences.

Discontinued operations for the second quarter 2011 includes the operating results of our Barnett properties for April 2011 and a pre-tax gain of $3.8 million recorded on the sale. Discontinued operations for the first six months ended 2011 includes the operating results of our Barnett properties through the date of the sale and a pre-tax gain of $3.8 million recorded on the sale. See also Note 4 and 5 for specific information regarding our discontinued operations.

Capital Resources, Liquidity and Financial Condition

Capital Resources

Our primary capital resources are net cash provided by operating activities, proceeds from the sale of assets and proceeds from financing activities. If internal cash flow and cash on hand do not meet our expectations, we may reduce our level of capital expenditures, and/or fund a portion of our capital expenditures under our bank credit facility, issue debt or equity securities and/or sell assets.

Cash Flow

Cash flows from operating activities primarily are affected by production and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operating activities also are impacted by changes in working capital. We sell substantially all of our natural gas, NGL and oil production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying, portion of our anticipated future natural gas and oil production for the next 12 to 36 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs can be funded by borrowing under the credit facility. As of June 30, 2011, we have entered into derivative agreements covering 75.1 Bcfe for 2011, 120.7 Bcfe for 2012 and 58.4 Bcfe for 2013.

Net cash provided from continuing operations for the six months ended June 30, 2011 was $276.8 million compared to $208.7 million in the six months ended June 30, 2010. Cash flow from continuing operations for the first six months of 2011 was higher than the same period of the prior year, as higher production from development activity, higher realized prices and a $15.0 million equity method investment distribution was partially offset by higher operating costs. 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 our consolidated statements of cash flows) in the six months ended June 30, 2011 was a decrease of $8.1 million compared to an increase of $8.2 million in the same period of the prior year.

During second quarter 2011, we completed the sale of primarily all of our Barnett properties for gross cash proceeds of $877.0 million, including assumed hedges and before post-closing adjustments, resulting in a pretax gain of $3.8 million. The net cash proceeds from the sale of these assets was determined in accordance with the purchase and sale agreement which provides for certain customary adjustments for matters occurring after the effective date of the sale, such as capital contributions and working capital adjustments. Differences between actual working capital amounts and estimated working capital amounts recorded as of June 30, 2011 will be recorded as income or loss from discontinued operations in future periods.

Net cash used in financing activities for the six months ended June 30, 2011 was $272.8 million compared to net cash provided from financing activities of $135.2 million in the same period of 2010. During the six months ended June 30, 2011, we:

	•		borrowed $490.8 million and repaid $764.8 million under our bank credit facility, ending the period with no outstanding borrowings under our credit facility;

	•		issued $500.0 million principal amount of 5.75% senior subordinated notes due 2021, at par;

	•		purchased or redeemed $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 at a redemption price of 102.31% and purchased or redeemed $250.0 million principal amount of our 7.5% senior subordinated notes due 2016 at a redemption price of 103.9%;

	•		spent $21.7 million related to debt issuance costs; and

	•		recorded a decrease of $58.3 million in cash overdrafts.

During the six months ended June 30, 2010, we:

•

borrowed $371.0 million and repaid $220.0 million under our bank credit facility, ending the period with a $30.0 million higher bank credit facility balance.

Credit Arrangements

On June 30, 2011, the bank credit facility had a $2.0 billion borrowing base, a $1.5 billion facility amount and we had no outstanding borrowings. The borrowing base represents an amount approved by the bank group that can be borrowed based on our assets, while our $1.5 billion facility amount is the amount we have requested that the banks commit to fund pursuant to the credit agreement. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. Remaining credit availability was $1.5 billion on July 22, 2011. Our bank group is comprised of twenty-seven commercial banks with no one bank holding more than 7.0% of the bank credit facility. We believe our large number of banks and relatively low hold levels allow for significant lending capacity should we elect to increase our $1.5 billion commitment up to the $2.0 billion borrowing base and also allow for flexibility should there be additional consolidation within the banking sector.

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, incur additional indebtedness, sell assets, enter into hedging contracts, change the nature of our business or operations, merge or consolidate or make certain investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with these covenants at June 30, 2011. See Note 9 to the accompanying consolidated financial statements for additional information.

In May 2011, we issued $500.0 million aggregate principal amount of 5.75% senior subordinated notes due 2021 (“5.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 5.75% Notes were issued at par. Interest on the 5.75% Notes is payable semi-annually in June and December and is guaranteed by substantially all of our subsidiaries. We may redeem the 5.75% Notes, in whole or in part, at any time on or after June 1, 2016, at redemption prices of 102.875% of the principal amount as of June 1, 2016 declining to 100.0% on June 1, 2019 and thereafter. Before June 2014, we may redeem up to 35% of the original aggregate principal amount of the 5.75% Notes at a redemption price equal to 105.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.75% 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. On closing, we used $112.9 million of the proceeds to redeem our 6.375% senior subordinated notes due 2015 and $207.1 million to redeem our 7.5% senior subordinated notes due 2016 as part of the tender offer described below.

called the remaining 2015 and 2016 notes, redeeming all of the remaining outstanding 2015 notes ($41.1 million) at 102.125% of par on June 24, 2011 and redeeming all of the remaining outstanding 2016 notes ($51.2 million) at 103.75% of par on June 24, 2011. During the second quarter 2011, we recognized an $18.6 million loss on extinguishment of debt, including transaction call premium cost as well as expensing of deferred financing cost on repurchased debt.

In June 2009, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability, subject to market conditions, to issue and sell an indeterminate amount of various types of registered debt and equity securities.

As we pursue our strategy, we may utilize various financing sources, including, to the extent available, fixed and floating rate debt, or common stock. We may also issue securities in exchange for oil and gas properties.

Liquidity

Our principal sources of short-term liquidity are cash on hand and unused borrowing capacity under our bank credit facility. As of June 30, 2011, we had no outstanding borrowings under our credit facility and we were in compliance with all of its debt covenants. After adjusting for $13.9 million of undrawn and outstanding letters of credit, we had approximately $1.5 billion of unused borrowing capacity as of June 30, 2011.

If internal cash flow and cash on hand do not meet our expectations, we may reduce our level of capital expenditures, and/or fund a portion of our capital expenditures using borrowings under our bank credit facility, issue debt or equity securities or receive cash from other sources, such as asset sales. We cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although we expect that internal operating cash flows, cash on hand and borrowing capacity under our bank credit facility will be adequate to fund capital expenditures and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet our future needs. For instance, the amount that we may borrow under the bank credit facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Estimates may differ from actual results. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our outstanding debt and credit ratings by rating agencies.

Capital Commitments

Our primary needs for cash are for capital expenditures on natural gas and oil assets, payment of contractual obligations, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally generated cash flow, proceeds from the disposition of assets or external financing sources. We expect we will be able to fund our needs for cash (excluding acquisitions) with internally-generated cash flows, cash on hand and liquidity under our credit facility, although no assurances can be given that such funding will be adequate to meet our future needs. We generally strive to limit our capital expenditures to internally-generated cash flow plus proceeds from asset sales. We establish a capital budget at the beginning of each calendar year. Our 2011 capital budget (excluding acquisitions) now stands at $1.38 billion and focuses on projects we believe will generate and lay the foundation for economic, long-term production growth.

Investing Activities

Net cash used in investing activities of continuing operations for the six months ended June 30, 2011 was $590.0 million compared to $202.5 million in the same period of 2010. During the six months ended June 30, 2011, we:

	•		spent $535.3 million on natural gas and oil property additions;

	•		spent $73.1 million on acreage primarily in the Marcellus Shale; and

	•		received proceeds of $23.4 million primarily from the sale of a low pressure pipeline.

During the six months ended June 30, 2010, we:

	•		spent $322.4 million on natural gas and oil property additions;

	•		spent $187.2 million on acreage primarily in the Marcellus Shale; and

	•		received proceeds of $318.6 million primarily from the sale of our Ohio oil and gas properties.

Dividends

On June 30, 2011, the Board of Directors declared a dividend of four cents per share ($6.4 million) on our common stock, which was paid on June 30, 2011 to stockholders of record at the close of business on June 17, 2011. Future dividends are at the discretion of the Board and, if declared, the Board may change the current dividend amount based on our liquidity and capital resources.

Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportations commitments and other purchase obligations. The table below summarizes our significant contractual obligations as of June 30, 2011 (in thousands).


	Payment due by period
	Remaining							2014
	2011		2012		2013			and 2015		Thereafter		Total
7.5% senior subordinated notes due 2017	$	—	$	—	$	—		$	—	$	250,000	$	250,000
7.25% senior subordinated notes due 2018		—		—		—			—		250,000		250,000
8.0% senior subordinated notes due 2019		—		—		—			—		300,000		300,000
6.75% senior subordinated notes due 2020		—		—		—			—		500,000		500,000
5.75% senior subordinated notes due 2021		—		—		—			—		500,000		500,000
Operating leases		5,762		12,863		10,041			18,890		28,574		76,130
Drilling rig commitments		32,163		52,305		14,673			896		—		100,037
Transportation commitments		45,315		90,361		89,768			175,187		503,940		904,571
Other purchase obligations		27,013		49,026		3,386			28		—		79,453
Derivative obligations ^(a)		—		6,384		(1,957	)		—		—		4,427
Asset retirement obligation liability ^(b)		4,020		8,801		1,137			4,168		56,240		74,366

Total contractual obligations ^(c)	$	114,273	$	219,740	$	117,048		$	199,169	$	2,388,754	$	3,038,984


^(a)		Derivative obligations represent net open derivative contracts valued as of June 30, 2011. While such payments will be funded by higher prices received from the sale of our production, production receipts may be received after our payments to counterparties, which can result in borrowings under our bank credit facility.

^(b)		The ultimate settlement and timing cannot be precisely determined in advance.

^(c)		This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets.

Debt Ratings

We receive debt credit ratings from two of the major ratings agencies, which are subject to regular reviews. We believe that each of the rating agencies consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in our debt ratings could negatively impact our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book Capitalization

Our net book capitalization at June 30, 2011 was $3.7 billion, consisting of $288.8 million of cash and cash equivalents, debt of $1.8 billion and stockholder’s equity of $2.2 billion. Our net debt to net book capitalization was 40.0 percent at June 30, 2011 and 46.9 percent at December 31, 2010.

Capital Requirements

We currently estimate our 2011 capital spending will approximate $1.38 billion (excluding acquisitions) and based on current projections is expected to be funded with internal cash flow, property sales and our bank credit facility. Acreage purchases during the first six months include $56.7 million of purchases in the Marcellus Shale, which were funded with borrowings under our credit facility. For the six months ended June 30, 2011, $587.3 million of our development and exploration spending was funded with internal cash flow, borrowings under our bank credit facility and asset sales. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may choose to sell assets, issue subordinated notes or other debt securities, or issue additional shares of stock to fund capital expenditures or acquisitions, extend maturities or repay debt.

Other Contingencies

We are involved in various legal actions, claims and other regulatory proceedings arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our liquidity or consolidated financial position. If an unfavorable ruling were to occur, there exists the possibility of a material adverse impact on our net income or loss in the period in which the ruling occurs.

Hedging — Natural Gas and Oil Prices

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. Historically, these contracts consisted of collars and fixed price swaps. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital program. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. In light of current worldwide economic uncertainties, we have employed a strategy to hedge a portion of our production looking out 12 to 36 months from each quarter. At June 30, 2011, we had open swap contracts covering 25.6 Bcf of natural gas at prices averaging $5.00 and 3.1 million barrels of NGLs (the C5 component) at an average price of $103.24 per barrel. At June 30, 2011, we had collars covering 189.1 Bcf of natural gas at weighted average floor and cap prices of $5.27 and $5.93 per mcf and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 and $80.00 per barrel. At June 30, 2011, we also had sold call options covering 2.7 million barrels of oil at a weighted average price of $83.15. The fair value of all of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of contract prices and a reference price, generally NYMEX, on June 30, 2011 was a net unrealized pre-tax gain of $61.1 million. The contracts expire monthly through December 2013. Settled transaction gains and losses for derivatives that qualify for hedge accounting are determined monthly and are included as increases or decreases in natural gas, NGLs and oil sales in the period the hedged production is sold. In the first six months of 2011, natural gas, NGLs and oil sales included realized hedging gains of $53.9 million compared to gains of $19.6 million in the same period of 2010.

At June 30, 2011, the following commodity derivative contracts were outstanding:


			Average
Period	Contract Type	Volume Hedged	Hedge Price
Natural Gas
2012	Swaps	70,192 Mmbtu/day	$	5.00
2011	Collars	333,200 Mmbtu/day	$	5.38-$6.23
2012	Collars	189,641 Mmbtu/day	$	5.32-$5.91
2013	Collars	160,000 Mmbtu/day	$	5.09-$5.65

Crude Oil
2012	Collars	2,000 bbls/day	$	70.00-$80.00
2011	Call options	5,500 bbls/day	$	80.00
2012	Call options	4,700 bbls/day	$	85.00

NGLs
2011	Swaps	7,000 bbls/day	$	104.17
2012	Swaps	5,000 bbls/day	$	102.59

Some of our derivatives do not qualify for hedge accounting or are not designated as a hedge but provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas and oil production. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value as unrealized derivative gains and losses in the accompanying consolidated balance sheets. We recognize all unrealized and realized gains and losses related to these contracts as derivative fair value income or loss in our consolidated statements of operations. As of June 30, 2011, derivatives on 53.7 Bcfe no longer qualify or are not designated for hedge accounting.

Interest Rates

At June 30, 2011, we had $1.8 billion of debt outstanding which bears interest at fixed rates averaging 6.9%.

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas and oil prices and the costs to produce our reserves. Natural gas and oil prices are subject to fluctuations that are beyond our ability to control or predict. During second quarter 2011, we received an average of $3.76 per mcf of gas and $92.46 per barrel of oil before derivative contracts compared to $3.75 per mcf of gas and $67.76 per barrel of oil in the same period of the prior year. Although certain of our costs are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated through the middle of 2008, commodity prices for oil and gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends put pressure not only on our operating costs but also on capital costs. Due to the decline in commodity prices since then, costs have generally moderated but are increasing in areas with high levels of drilling activity that utilize specialized services for horizontal drilling and completions. We expect costs in 2011 to continue to be a function of supply and demand.

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 natural gas, NGL and oil prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas, NGL and oil prices have been volatile and unpredictable for many years.

Commodity Price Risk

We periodically enter into derivative arrangements with respect to our natural gas, oil and NGL production. These arrangements are intended to reduce the impact of natural gas and oil price fluctuations. Some of our derivatives have been swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which establish a minimum floor price and a predetermined ceiling price. We have also entered into call option derivative contracts under which we sold call options in exchange for a premium from the counterparty. Historically, we applied hedge accounting to derivatives utilized to manage price risk associated with our natural gas and oil production. Accordingly, we recorded the change in the fair value of our swap and collar contracts under the balance sheet caption accumulated other comprehensive income and into natural gas, NGLs and oil 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 in derivative fair value income or loss in our consolidated statements of operations. Some of our derivatives do not qualify for hedge accounting but provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGL and oil production. These contracts are accounted for using the mark-to-market accounting method. Under this method, the contracts are carried at their fair value in unrealized derivative gains and losses in our consolidated balance sheets. We recognize all unrealized and realized gains and losses related to these contracts in derivative fair value income or loss in our consolidated statements of operations. 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. Our derivative counterparties include ten financial institutions, of which all but one are in our bank group. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.

As of June 30, 2011, we had swaps covering 25.6 Bcf of natural gas and 3.1 million barrels of NGLs, collars covering 189.1 Bcf of natural gas and 0.7 million barrels of oil and oil call options for 2.7 million barrels of oil. These contracts expire monthly through December 2013. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of June 30, 2011, approximated a net unrealized pre-tax gain of $61.1 million.

We expect our NGL production to continue to increase. In the first six months 2011, we entered into NGL swap contracts for the natural gasoline component (C5) of NGLs. In our Marcellus Shale operations, propane is a large product component of our NGL production and we believe NGL prices are somewhat seasonal. Therefore, the percentage of NGL prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand.

At June 30, 2011, the following commodity derivative contracts were outstanding:


					Fair Market Value
					as of
					June 30, 2011
Period	Contract Type	Volume Hedged	Average Hedge Price		Asset (Liability)
					(in thousands)
Natural Gas
2012	Swaps	70,192 Mmbtu/day	$	5.00	$	4,184
2011	Collars	333,200 Mmbtu/day	$	5.38-$6.23	$	59,271
2012	Collars	189,641 Mmbtu/day	$	5.32-$5.91	$	42,298
2013	Collars	160,000 Mmbtu/day	$	5.09-$5.65	$	8,768

Crude Oil
2012	Collars	2,000 bbls/day	$	70.00-$80.00	$	(15,830	)
2011	Call options	5,500 bbls/day	$	80.00	$	(17,768	)
2012	Call options	4,700 bbls/day	$	85.00	$	(33,582	)

NGLs
2011	Swaps	7,000 bbls/day	$	104.17	$	5,797
2012	Swaps	5,000 bbls/day	$	102.59	$	7,952

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. We currently have not entered into any basis derivatives.

The following table shows the fair value of our swaps, collars and call options and the hypothetical change in the fair value that would result from a 10% and a 25% change in commodity prices at June 30, 2011 (in thousands):


				Hypothetical Change in						Hypothetical Change in
				Fair Value						Fair Value
				Increase of						Decrease of
	Fair Value			10%			25%			10%		25%
Swaps	$	17,934		$	(42,676	)	$	(106,455	)	$	42,932	$	107,329
Collars		94,507			(92,270	)		(232,561	)		103,542		257,053
Call options		(51,351	)		(22,950	)		(60,069	)		20,198		40,886

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported

within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2011 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15-d-15(f) under the Exchange Act) during the quarter ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1A. RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

ITEM 6. EXHIBITS

(a) EXHIBITS


Exhibit
Number		Exhibit Description

3.1		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 May 5, 2004, as amended by the Certificate of Second 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 (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)

10.1		Second Amendment to the Range Resources Corporation Amended and Restated 2005 Equity Based Compensation Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2011)

31.1*		Certification by the Chairman 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 Chairman 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

101. INS**		XBRL Instance Document

101. SCH**		XBRL Taxonomy Extension Schema

101. CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF**		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB**		XBRL Taxonomy Extension Label Linkbase Document

101. PRE**		XBRL Taxonomy Extension Presentation Linkbase Document


*		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.

Date: July 25, 2011


	RANGE RESOURCES CORPORATION
	By:	/s/ ROGER S. MANNY
		Roger S. Manny
		*Executive Vice President and Chief Financial Officer*

Date: July 25, 2011


	RANGE RESOURCES CORPORATION
	By:	/s/ DORI A. GINN
		Dori A. Ginn
		*Principal Accounting Officer and Vice President Controller*

II-1

Exhibit index


Exhibit
Number		Exhibit Description

3.1		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 May 5, 2004, as amended by the Certificate of Second 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 (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

3.2		Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 20, 2010)

10.1		Second Amendment to the Range Resources Corporation Amended and Restated 2005 Equity Based Compensation Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2011)

31.1*		Certification by the Chairman 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 Chairman 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

101. INS**		XBRL Instance Document

101. SCH**		XBRL Taxonomy Extension Schema

101. CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF**		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB**		XBRL Taxonomy Extension Label Linkbase Document

101. PRE**		XBRL Taxonomy Extension Presentation Linkbase Document


*		filed herewith

**		furnished herewith

II-2