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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2010	Feb. 25, 2011	Jun. 30, 2010
Document and Entity Information [Abstract]
Entity Registrant Name	RANGE RESOURCES CORP
Entity Central Index Key	0000315852
Document Type	10-K
Document Period End Date	Dec. 31, 2010
Amendment Flag	false
Document Fiscal Year Focus	2010
Document Fiscal Period Focus	FY
Company Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,999,629,000
Entity Common Stock Shares Outstanding		160,491,399

Consolidated Balance Sheets - USD ($) $ in Thousands	12 Months Ended
Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Current assets:
Cash and cash equivalents	$ 2,848	$ 767
Accounts receivable, less allowance for doubtful accounts of $5,001 and $2,176	105,983	123,622
Deferred tax asset	0	8,054
Unrealized derivative gain	131,450	21,545
Inventory and other	21,433	21,292
Total current assets	261,714	175,280
Unrealized derivative gain	0	4,107
Equity method investments	155,105	146,809
Natural gas and oil properties, successful efforts method	6,561,454	6,308,707
Accumulated depletion and depreciation	(1,639,397)	(1,409,888)
Natural gas and oil properties, successful efforts method	4,922,057	4,898,819
Transportation and field assets	136,088	161,034
Accumulated depreciation and amortization	(61,355)	(69,199)
Transportation and field assets, net	74,733	91,835
Other assets	84,977	79,031
Total assets	5,498,586	5,395,881
Current liabilities:
Accounts payable	312,475	214,548
Asset retirement obligations	4,020	2,446
Accrued liabilities	69,678	58,585
Deferred tax liability	11,848	0
Accrued interest	32,189	24,037
Unrealized derivative loss	352	14,488
Total current liabilities	430,562	314,104
Bank debt	274,000	324,000
Subordinated notes	1,686,536	1,383,833
Deferred tax liability	672,041	776,965
Unrealized derivative loss	13,412	271
Deferred compensation liability	134,488	135,541
Asset retirement obligations and other liabilities	63,786	82,578
Total liabilities	$ 3,274,825	$ 3,017,292
Commitments and contingencies
Stockholders' Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding	$ 0	$ 0
Common stock, $0.01 par, 475,000,000 shares authorized, 160,113,608 issued at December 31, 2010 and 158,336,264 issued at December 31, 2009	1,601	1,583
Common stock held in treasury, 204,556 shares at December 31, 2010 and 217,327 shares at December 31, 2009	(7,512)	(7,964)
Additional paid-in capital	1,820,503	1,772,020
Retained earnings	341,699	606,529
Accumulated other comprehensive income	67,470	6,421
Total stockholders' equity	2,223,761	2,378,589
Total liabilities and stockholders' equity	$ 5,498,586	$ 5,395,881

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2010	Dec. 31, 2009
Current assets:
Allowance for doubtful accounts on accounts receivables	$ 5,001,000	$ 2,176,000
Stockholders' Equity
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	160,113,608	158,336,264
Common stock held in treasury shares	204,556	217,327

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Revenues and other income:
Natural gas, NGL and oil sales	$ 246,503	$ 219,560	$ 206,784	$ 236,760	$ 242,087	$ 202,122	$ 192,523	$ 203,189	$ 909,607	$ 839,921	$ 1,226,560
Transportation and gathering	(65)	(1,634)	674	2,093	(3,605)	2,444	2,152	(505)	1,068	486	4,577
Derivative fair value income	(7,226)	9,981	6,546	42,333	1,237	(482)	(9,856)	75,547	51,634	66,446	71,861
Gain on the sale of assets	(1,514)	67	10,176	68,868	10,374	32	(29)	36	77,597	10,413	20,166
Other	1,020	(1,013)	637	(1,575)	(3,262)	(475)	(4,358)	(1,830)	(931)	(9,925)	1,509
Total revenues and other income	238,718	226,961	224,817	348,479	246,831	203,641	180,432	276,437	1,038,975	907,341	1,324,673
Costs and expenses:
Direct operating	36,500	34,287	29,775	31,040	31,731	31,111	34,828	35,541	131,602	133,211	142,387
Production and ad valorem taxes	8,619	8,873	8,090	8,070	8,748	7,600	7,564	8,257	33,652	32,169	55,172
Exploration	16,743	15,236	14,473	14,635	10,876	10,902	11,368	13,339	61,087	46,485	67,690
Abandonment and impairment of unproved properties	23,533	20,534	13,497	12,407	28,959	24,053	40,954	19,572	69,971	113,538	47,355
General and administrative	40,042	36,523	35,836	28,170	31,378	29,928	29,103	24,910	140,571	115,319	92,308
Termination costs	514			7,938	1,639	840			8,452	2,479
Deferred compensation plan	14,978	(5,347)	(14,135)	(5,712)	1,438	16,445	756	12,434	(10,216)	31,073	(24,689)
Interest expense	36,320	33,806	30,779	30,287	30,550	30,633	29,555	26,629	131,192	117,367	99,748
Loss on early extinguishment of debt		5,351							5,351
Depletion, depreciation and amortization	92,116	91,768	90,997	88,626	103,261	97,208	88,713	84,320	363,507	373,502	299,831
Impairment of proved properties	463,244			6,505	930				469,749	930
Total costs and expenses	732,609	241,031	209,312	221,966	249,510	248,720	242,841	225,002	1,404,918	966,073	779,802
(Loss) income before income taxes	(493,891)	(14,070)	15,505	126,513	(2,679)	(45,079)	(62,409)	51,435	(365,943)	(58,732)	544,871
Income tax (benefit) expense
Current	(826)	(10)			(560)	(695)	619		(836)	(636)	4,268
Deferred	(175,346)	(5,892)	6,453	48,934	14,658	(14,566)	(23,145)	18,827	(125,851)	(4,226)	189,563
Total tax (benefit) provision	(176,172)	(5,902)	6,453	48,934	14,098	(15,261)	(22,526)	18,827	(126,687)	(4,862)	193,831
Net (loss) income	$ (317,719)	$ (8,168)	$ 9,052	$ 77,579	$ (16,777)	$ (29,818)	$ (39,883)	$ 32,608	$ (239,256)	$ (53,870)	$ 351,040
(Loss) income per common share:
Basic	$ (2.02)	$ (0.05)	$ 0.06	$ 0.50	$ (0.11)	$ (0.19)	$ (0.26)	$ 0.21	$ (1.53)	$ (0.35)	$ 2.32
Diluted	$ (2.02)	$ (0.05)	$ 0.06	$ 0.48	$ (0.11)	$ (0.19)	$ (0.26)	$ 0.21	$ (1.53)	$ (0.35)	$ 2.25
Weighted average common shares outstanding:
Basic									156,874	154,514	151,116
Diluted									156,874	154,514	155,943

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Operating activities:
Net (loss) income	$ (239,256)	$ (53,870)	$ 351,040
Adjustments to reconcile net income to net cash provided from operating activities:
Loss from equity method investments	1,482	13,699	218
Deferred income tax (benefit) expense	(125,851)	(4,226)	189,563
Depletion, depreciation and amortization and proved property impairment	833,256	374,432	299,831
Exploration dry hole costs	3,700	2,159	13,371
Mark-to-market on natural gas and oil derivatives not designated as hedges	2,086	115,909	(85,594)
Abandonment and impairment of unproved properties	69,971	113,538	47,355
Unrealized derivative (gain) loss	(2,387)	1,696	(1,695)
Allowance for bad debts	3,608	1,351	450
Amortization of deferred financing costs and other	10,072	8,755	2,900
Deferred and stock-based compensation	34,964	73,402	6,621
Gains on sale of assets and other	(77,597)	(10,413)	(19,507)
Changes in working capital:
Accounts receivable	(1,937)	1,007	6,701
Inventory and other	(333)	(1,463)	(9,246)
Accounts payable	2,867	(44,765)	10,663
Accrued liabilities and other	(1,323)	464	12,096
Net cash provided from operating activities	513,322	591,675	824,767
Investing activities:
Additions to natural gas and oil properties	(817,033)	(541,182)	(881,950)
Additions to field service assets	(14,944)	(33,098)	(36,076)
Acreage and proved property purchases	(296,503)	(139,288)	(834,758)
Investment in equity method investment and other assets	(45)	7,076	(44,162)
Proceeds from disposal of assets	327,765	234,076	68,231
Purchase of marketable securities held by the deferred compensation plan	(17,670)	(7,470)	(11,208)
Proceeds from the sales of marketable securities held by the deferred compensation plan	19,572	6,079	8,146
Net cash used in investing activities	(798,858)	(473,807)	(1,731,777)
Financing activities:
Borrowing on credit facilities	1,055,000	707,000	1,476,000
Repayment on credit facilities	(1,105,000)	(1,076,000)	(1,086,500)
Issuance of subordinated notes	500,000	285,201	250,000
Repayment of subordinated notes	(202,458)
Dividends paid	(25,574)	(25,169)	(24,625)
Debt issuance costs	(9,600)	(6,399)	(8,710)
Issuance of common stock	5,903	12,737	291,183
Change in cash overdrafts	64,100	(22,370)	4,420
Proceeds from the sales of common stock held by the deferred compensation plan	5,246	7,201	5,303
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases		(55)	(3,326)
Net cash provided from (used in) financing activities	287,617	(117,854)	903,745
Increase (decrease) in cash and cash equivalents	2,081	14	(3,265)
Cash and cash equivalents at beginning of year	767	753	4,018
Cash and cash equivalents at end of year	$ 2,848	$ 767	$ 753

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2010	Mar. 31, 2010	Dec. 31, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Statement [Line Items]
Beginning Balance		$ 2,378,589		$ 2,451,342	$ 2,378,589	$ 2,451,342	$ 1,717,736
Issuance of common stock					26,156	57,601	291,881
Stock-based compensation expense					22,797	19,771	16,562
Common dividends declared					(25,574)	(25,169)	(24,625)
Treasury stock purchase							(3,223)
Other comprehensive income					61,049	(71,086)	101,971
Net (loss) income	$ (317,719)	77,579	$ (16,777)	32,608	(239,256)	(53,870)	351,040
Adoption of ASC 825, net of tax							0
Ending Balance	2,223,761		2,378,589		2,223,761	2,378,589	2,451,342
Common stock
Statement [Line Items]
Beginning Balance		$ 1,583		$ 1,556	$ 1,583	$ 1,556	$ 1,497
Beginning Balance, Shares		158,336		155,609	158,336	155,609	149,667
Issuance of common stock					$ 18	$ 27	$ 59
Issuance of common stock, Shares					1,778	2,727	5,942
Ending Balance	$ 1,601		$ 1,583		$ 1,601	$ 1,583	$ 1,556
Ending Balance, Shares	160,114		158,336		160,114	158,336	155,609
Treasury common stock
Statement [Line Items]
Beginning Balance		$ (7,964)		$ (8,557)	$ (7,964)	$ (8,557)	$ (5,334)
Treasury stock issuance					452	593
Treasury stock purchase							(3,223)
Ending Balance	$ (7,512)		$ (7,964)		(7,512)	(7,964)	(8,557)
Additional paid-in capital
Statement [Line Items]
Beginning Balance		1,772,020		1,695,268	1,772,020	1,695,268	1,386,884
Issuance of common stock					26,138	57,574	291,822
Stock-based compensation expense					22,797	19,771	16,562
Treasury stock issuance					(452)	(593)
Ending Balance	1,820,503		1,772,020		1,820,503	1,772,020	1,695,268
Retained earnings
Statement [Line Items]
Beginning Balance		606,529		685,568	606,529	685,568	360,427
Common dividends declared					(25,574)	(25,169)	(24,625)
Net (loss) income					(239,256)	(53,870)	351,040
Adoption of ASC 825, net of tax							(1,274)
Ending Balance	341,699		606,529		341,699	606,529	685,568
Accumulated other comprehensive (loss) income
Statement [Line Items]
Beginning Balance		$ 6,421		$ 77,507	6,421	77,507	(25,738)
Other comprehensive income					61,049	(71,086)	101,971
Adoption of ASC 825, net of tax							1,274
Ending Balance	$ 67,470		$ 6,421		$ 67,470	$ 6,421	$ 77,507

Consolidated Statements of Stockholders' Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Statement [Line Items]
Common dividends declared per share \| (per share)	$ 0.16	$ 0.16	$ 0.16
Retained earnings
Statement [Line Items]
Common dividends declared per share	$ 0.16	$ 0.16	$ 0.16

Consolidated Statements of Comprehensive (Loss) Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Consolidated Statements of Comprehensive (Loss) Income [Abstract]
Net (loss) income	$ (239,256)	$ (53,870)	$ 351,040
Other comprehensive income (loss):
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss), net of taxes	(39,931)	(127,965)	39,416
Change in unrealized deferred hedging gains (losses), net of taxes	100,980	56,879	62,555
Total comprehensive (loss) income	$ (178,207)	$ (124,956)	$ 453,011

Summary of Organization and Nature of Business	12 Months Ended
Summary of Organization and Nature of Business	Dec. 31, 2010
Summary of Organization and Nature of Business [Abstract]
SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS	(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas and oil company primarily engaged in the exploration, development and acquisition of natural gas properties in the Appalachian and Southwestern 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 is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2010

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in other revenues in the accompanying consolidated statements of operations. All material intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas and oil reserves. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation, which includes the reclassification of severance costs associated with the closing of our Houston office and the sale of our New York properties from direct operating expense, exploration expense and general and administrative expense to termination costs. The accompanying consolidated statements of operations also include the reclassification in all periods of the gain on sale of assets from other revenues and the reclassification of impairment of proved properties from depletion, depreciation and amortization. These reclassifications did not impact our net income or loss, stockholders’ equity or cash flows.

Income per Common Share

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding. Diluted income (loss) per common share assumes issuance of stock compensation awards, provided the effect is not antidilutive.

Business Segment Information

We have evaluated how Range is organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, natural gas liquids (“NGLs”) and oil. We consider our gathering, processing and marketing functions as ancillary to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability without regard to individual areas or segments.

Revenue Recognition and Gas Imbalances

Natural gas, NGL and oil revenues are recognized when the products are sold and delivery to the purchaser has occurred. We recognize the cost of revenues, such as transportation and compression expense, as a reduction to revenue. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $5.0 million at December 31, 2010 compared to $2.2 million at December 31, 2009. During the year ended 2010, we recorded $3.6 million of bad debt expense compared to $1.4 million in the same period of the prior year.

We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of the gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2009 were not significant. At December 31, 2010, we had recorded a net liability of $587,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.

Marketable Securities

Holdings of equity securities held in our deferred compensation plans qualify as trading and are recorded at fair value. Investments in the deferred compensation plans are in mutual funds and consist of various publicly-traded mutual funds. These funds are made up of investments which include equities and money market instruments.

Inventories

Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market, on a first-in, first-out basis. Our inventory is primarily acquired for use in future drilling operations.

Natural Gas and Oil Properties

We follow the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. NGLs and oil are converted to gas equivalent basis or mcfe at the rate of one barrel of oil equating to 6 mcf of natural gas. Depreciation, depletion and amortization of proved producing properties is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009. Accounting Standards Codification (ASC) 2010-3 clarified that the effect of the change in price encompassed in the new SEC rules was a change in accounting principle inseparable from a change in estimate for 2009 and was accounted for prospectively. For 2009, we estimated the effect of this change in estimate increased depletion, depreciation and amortization expense by approximately $3.4 million ($2.2 million after tax) primarily due to lower prices reflected in our estimated reserves.

Our natural gas and oil producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. For additional information regarding 2010 and 2009 proved property impairments, see Note 11.

Proceeds from the disposal of natural gas and oil producing properties that are part of an entire amortization group are credited to the net book value of their amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $811.8 million in 2010 compared to $774.5 million in 2009. We have recorded abandonment and impairment expense related to unproved properties of $70.0 million in 2010 compared to $113.5 million in 2009 and to $47.4 million in 2008.

Transportation and Field Assets

Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these pipeline systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. We receive third-party income for providing field service and certain transportation services, which is recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Buildings are depreciated over 10 to 15 years. Depreciation expense was $16.2 million in 2010 compared to $31.7 million in 2009 and $13.7 million in 2008. The fourth quarter 2009 includes accelerated depreciation expense of $10.3 million related to an interim processing plant in our Appalachian region that was dismantled in first quarter 2010 and replaced with permanent facilities.

Other Assets

The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2010 include $27.9 million of unamortized debt issuance costs, $47.8 million of marketable securities held in our deferred compensation plans and $9.3 million of other investments.

Accounts Payable

Included in accounts payable at December 31, 2010 and 2009, are liabilities of approximately $97.2 million and $33.1 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in our applicable bank accounts.

Stock-based Compensation Arrangements

The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.

We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Through December 2010, 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 hedged transaction is probable to not occur, any unrealized gains or losses is recognized immediately in derivative fair value income in the accompanying consolidated statements of operations. During 2010, we recognized a gain of $11.6 million (pre-tax) compared to a gain of $5.4 million in 2009 and a loss of $583,000 in 2008 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives.

We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas and oil production. Accordingly, we record changes in the fair value of our collar and call option contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets. Gains or losses on these collar and call options contracts are reclassified out of AOCI and into natural gas, NGL and oil sales when the underlying physical transaction occurs and the hedging contract is settled. Any hedge ineffectiveness associated with a contract qualifying and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income on the accompanying consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).

Realized and unrealized gains and losses on derivatives that are not designated as hedges (or “non-hedge derivatives”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value income in the accompanying consolidated statements of operations. We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreement that effectively fix our basis adjustments.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. The depreciation will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets.

Deferred Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income including tax credits and operating loss carryforwards.

Accumulated Other Comprehensive Income (Loss)

The following details the components of AOCI and related tax effects for the three years ended December 31, 2010. Amounts included in AOCI relate to our derivative activity.


	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive loss at December 31, 2007	$	(41,352	)	$	15,614		$	(25,738	)
Contract settlements reclassified to income		63,574			(24,158	)		39,416
Change in unrealized deferred hedging gains		98,008			(35,453	)		62,555
Adoption of fair value accounting for trading securities		2,022			(748	)		1,274


Accumulated other comprehensive income at December 31, 2008		122,252			(44,745	)		77,507
Contract settlements reclassified to income		(203,119	)		75,154			(127,965	)
Change in unrealized deferred hedging gains		91,059			(34,180	)		56,879


Accumulated other comprehensive income at December 31, 2009		10,192			(3,771	)		6,421
Contract settlements reclassified to income		(64,772	)		24,841			(39,931	)
Change in unrealized deferred hedging gains		165,642			(64,662	)		100,980


Accumulated other comprehensive income at December 31, 2010	$	111,062		$	(43,592	)	$	67,470

Accounting Pronouncements Implemented

Recently Adopted

Accounting standards for variable interest entities were amended by the Financial Accounting Standards Board (the “FASB”) in September 2009. The new accounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended accounting standard for variable interest entities requires reconsideration for determining whether an entity is a variable entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. The adoption of this guidance did not have an impact on our consolidated results of operations, financial position or cash flows.

A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (a) the different classes of assets and liabilities measured at fair value, (b) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (c) the gross presentation of purchases, sales, issuances and settlements for the roll forward of Level 3 activity, and (d) the transfers in and out of Levels 1 and 2. We adopted all aspects of this standard in first quarter 2010. This adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows. See Note 11 for our disclosures about fair value measurements.

In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in first quarter 2010. The adoption of this guidance did not have an impact on our financial statements.

Accounting Pronouncements Not Yet Adopted

In December 2010, the FASB issued ASU No. 2010-29, which updates the guidance in ASC Topic 805, Business Combinations. The objective of ASU 2010-29 is to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The amendments in ASU 2010-29 specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments affect any public entity as defined by ASC 805 that enters into business combinations that are material on an individual or aggregate basis. This guidance will become effective for us for acquisitions occurring on or after the beginning of our 2012 fiscal year. We do not expect the adoption of this guidance will have a material impact upon our financial position or results of operations.

Dispositions And Acquisitions	12 Months Ended
Dispositions And Acquisitions	Dec. 31, 2010
Dispositions and Acquisitions [Abstract]
DISPOSITIONS AND ACQUISITIONS	(3) DISPOSITIONS AND ACQUISITIONS Dispositions 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. The total proceeds we received were approximately $323.0 million and we recorded a gain of $77.6 million. The agreement had an effective date of January 1, 2010, and consequently operating net revenue after January 1, 2010 was 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 credit facility. In second quarter 2009, we sold certain oil properties located in West Texas for proceeds of $181.8 million. In fourth quarter 2009, we sold natural gas properties in New York for proceeds of $36.3 million. The proceeds from the sale of these properties were credited to natural gas and oil properties, with no gain or loss recognized, as the dispositions did not materially impact the depletion rate of the remaining properties in the amortization base. Additionally, in fourth quarter 2009, we sold Marcellus Shale acreage for $11.2 million and we recognized a gain of $10.4 million. In first quarter 2008, we sold East Texas properties for proceeds of $64.0 million and recorded a gain of $20.2 million. In October 2010, we announced our plan to offer for sale our Barnett Shale properties in North Central Texas. The properties include approximately 360 producing wells and 700 proved and unproved drilling locations. The data room opened in December 2010 and on February 28, 2011, we announced that we signed a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to normal post-closing adjustments. However, the completion of the sale is dependent upon customary prospective buyer due diligence procedures and there can be no assurance the sale will be completed or that there will not be changes to the sales price. (see also Note 11). Acquisitions Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. In June 2010, we purchased proved and unproved natural gas properties in Virginia for approximately $134.5 million. After recording asset retirement obligations, the purchase price allocated $131.3 million to proved property and $3.7 million to unproved property. We used proceeds from our like-kind exchange account to fund this acquisition (see Dispositions above). No pro forma information has been provided as the acquisition was not considered significant. In 2009, we completed no material acquisitions. In 2008, we completed several acquisitions of Barnett Shale producing and unproved properties for $331.2 million. After recording asset retirement obligations and transactions costs of $827,000, the purchase price allocated to proved properties was $232.9 million and unproved properties was $99.4 million.

Income Taxes

12 Months Ended

Dec. 31, 2010

Income Taxes [Abstract]

INCOME TAXES

(4) INCOME TAXES

Our income tax benefit was $126.7 million for the year ended December 31, 2010 compared to income tax benefit of $4.9 million in 2009 and income tax expense of $193.8 million in 2008. A reconciliation between the statutory federal income tax rate and our effective income tax (benefit) rate is as follows:


	Year Ended December 31,
	2010			2009			2008
Federal statutory tax rate		(35.0	%)		(35.0	%)		35.0	%
State		(0.3	)		29.3			1.8
Valuation allowance		0.6			(2.8	)		(0.2	)
Other		0.1			0.2			(1.0	)

Consolidated effective tax (benefit) rate		(34.6	%)		(8.3	%)		35.6	%

Income tax (benefit) provision attributable to (loss) income before income taxes consists of the following:


	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Current:
U.S. federal	$	—		$	(1,000	)	$	1,000
U.S. state and local		(836	)		364			3,268

	$	(836	)	$	(636	)	$	4,268


Deferred:
U.S. federal	$	(125,319	)	$	(20,913	)	$	186,436
U.S. state and local		(532	)		16,687			3,127

	$	(125,851	)	$	(4,226	)	$	189,563


Total tax (benefit) provision	$	(126,687	)	$	(4,862	)	$	193,831

Significant components of deferred tax assets and liabilities are as follows:


	December 31,
	2010			2009
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	5,857		$	3,337
Current portion of asset retirement obligation		1,579			952
Other		4,106			6,207
Current portion of net operating loss carryforward		17,586			—

Total current		29,128			10,496


Non-current
Net operating loss carryforward		85,120			72,131
Deferred compensation		49,933			53,869
AMT credits and other credits		3,211			3,815
Non-current portion of asset retirement obligation		23,127			29,642
Cumulative unrealized mark-to-market loss		9,826			8,625
Other		23,481			20,311
Valuation allowance		(4,841	)		(2,555	)

Total non-current		189,857			185,838


Deferred tax liabilities:
Current
Net unrealized gain in AOCI		(40,976	)		(2,443	)

Total current		(40,976	)		(2,443	)


Non-current
Depreciation, depletion and investments		(858,502	)		(959,931	)
Net unrealized gain in AOCI		(2,616	)		(1,328	)
Other		(780	)		(1,543	)

Total non-current		(861,898	)		(962,802	)


Net deferred tax liability	$	(683,889	)	$	(768,911	)

At December 31, 2010, deferred tax liabilities exceeded deferred tax assets by $683.9 million, with $43.6 million of deferred tax liability related to net deferred hedging gains included in AOCI. As of December 31, 2010, we have a $4.8 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to top executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m). As of December 31, 2009, we had a valuation allowance of $600,000 recorded against our capital loss carryover and a $2.0 million valuation allowance on the deferred tax asset related to our deferred compensation plan.

At December 31, 2010, we had regular net operating loss (“NOL”) carryforwards of $413.2 million and alternative minimum tax (“AMT”) NOL carryforwards of $363.9 million that expire between 2012 and 2030. Our deferred tax asset related to regular NOL carryforwards at December 31, 2010 was $102.7 million, which is net of the ASC 718 Stock Compensation reduction for unrealized benefits. Regular NOLs generally offset taxable income and to such extent, no income tax payments are required. At December 31, 2010, we have AMT credit carryforwards of $665,000 that are not subject to limitation or expiration.

We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Mississippi, Ohio, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in New Mexico, Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years after 2006 and we are subject to various state tax examinations for years after 2005. We have not extended the statute of limitation period in any tax jurisdiction. Our continuing policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2010. Throughout 2010, our unrecognized tax benefits were not material.

(Loss) Income Per Common Share

12 Months Ended

Dec. 31, 2010

Income (loss) per common share [Abstract]

Income (loss) per common share

(5) (LOSS) INCOME PER COMMON SHARE

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


	Year Ended December 31,
	2010			2009			2008
Numerator:
Net (loss) income	$	(239,256	)	$	(53,870	)	$	351,040
Less: Basic income allocable to participating securities ^(a)		(453	)		—			—

Basic net (loss) income attributable to common shareholders		(239,709	)		(53,870	)		351,040
Diluted adjustments to income allocable to participating securities ^(a)		—			—			—

Diluted net (loss) income attributable to common shareholders	$	(239,709	)	$	(53,870	)	$	351,040


Denominator:
Weighted average common shares outstanding — basic		156,874			154,514			151,116
Effect of dilutive securities:
Employee stock options, SARs and stock held in the deferred compensation plan		—			—			4,876
Treasury shares		—			—			(49	)

Weighted average common shares outstanding — diluted		156,874			154,514			155,943


(Loss) income per common share:
Basic — net (loss) income	$	(1.53	)	$	(0.35	)	$	2.32
Diluted — net (loss) income	$	(1.53	)	$	(0.35	)	$	2.25


^(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.

Weighted average common shares — basic excludes 2.8 million shares at December 31, 2010, 2.6 million shares at December 31, 2009 and 2.3 million shares at December 31, 2008 of restricted stock held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Stock appreciation rights (“SARs”) of 880,000 for the year ended December 31, 2008 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations. Due to our net loss from operations for the years ended December 31, 2010 and December 31, 2009, we excluded all outstanding stock options, stock appreciation rights and restricted stock from the computations of diluted net income per share because the effect would have been anti-dilutive.

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2010

Suspended Exploratory Well Costs [Abstract]

SUSPENDED EXPLORATORY WELL COSTS

(6) SUSPENDED EXPLORATORY WELL COSTS

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to expense. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2010, 2009 and 2008 (in thousands):


	2010			2009			2008
Balance at beginning of period	$	19,052		$	47,623		$	15,053
Additions to capitalized exploratory well costs pending the determination of proved reserves		28,897			26,216			43,968
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(24,041	)		(52,849	)		(3,847	)
Capitalized exploratory well costs charged to expense		—			(1,938	)		(7,551	)

Balance at end of period		23,908			19,052			47,623
Less exploratory well costs that have been capitalized for a period of one year or less		(13,181	)		(10,778	)		(41,681	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	10,727		$	8,274		$	5,942


Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		4			6			3

As of December 31, 2010, the $10.7 million of capitalized exploratory well costs that have been capitalized for more than one year relates primarily to wells waiting on pipelines, with three of these wells in our Marcellus Shale area. The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of December 31, 2010 (in thousands):


	Total		2010		2009		2008
Capitalized exploratory well costs that have been capitalized for more than one year	$	10,727	$	4,546	$	4,602	$	1,579

Indebtedness

12 Months Ended

Dec. 31, 2010

Indebtedness [Abstract]

INDEBTEDNESS

(7) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2010 is shown parenthetically). No interest was capitalized during 2010, 2009, and 2008 (in thousands):


	December 31,
	2010		2009
Bank debt (2.7%)	$	274,000	$	324,000

Senior subordinated notes:
7.375% senior subordinated notes due 2013, net of $1,638 discount in 2009		—		198,362
6.375% senior subordinated notes due 2015		150,000		150,000
7.5% senior subordinated notes due 2016, net of $317 and $363 discount, respectively		249,683		249,637
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 $13,147 and $14,166 discount, respectively		286,853		285,834
6.75% senior subordinated notes due 2020		500,000		—

Total debt	$	1,960,536	$	1,707,833

Bank Debt

In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On December 31, 2010, the facility amount was $1.25 billion and the borrowing base 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-six commercial banks, with no one bank holding more than 5% of the total facility. The facility amount may be increased 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 increase. As of December 31, 2010, the outstanding balance under the bank credit facility was $274.0 million as well as $5.4 million of undrawn letters of credit leaving $970.1 million of borrowing capacity available under the facility amount. The loan matures on October 25, 2012. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.875% to 1.625% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.75% to 2.5%. 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 of the base rate loans to LIBOR loans. The weighted average interest rate was 2.2% for the year ended December 31, 2010 compared to 2.4% for the year ended December 31, 2009 and 4.4% for the year ended December 31, 2008. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2010, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.875% on our base rate loans.

Subsequent Development

On February 18, 2011, we entered into an amended and restated revolving bank facility, which replaced our previous bank credit facility. The new facility, secured by substantially all of our assets, provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. At closing, the facility amount was $1.5 billion, the borrowing base was $2.0 billion and there was $1.0 billion of borrowing capacity available under the facility amount. The new bank credit facility provides for a borrowing base subject to redetermination semi-annually each April and October and for event-driven unscheduled redeterminations. The new 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 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 increase. As of February 25, 2011, the outstanding balance under the bank credit facility was $440.0 million and of undrawn letters of credit leaving $1.1 billion of borrowing capacity available under the facility amount. The loan matures on February 18, 2016. Borrowings under the bank facility can either be at 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 2.5%. 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 of the base rate loans to LIBOR loans. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At closing, the commitment fee was 0.375% and the interest rate margin was 1.50% on our LIBOR loans and 0.50% on our base rate loans.

Senior Subordinated Notes

In August 2010, we issued $500.0 million aggregate principal amount of 6.75% senior subordinated notes due 2020 (“6.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 6.75% Notes were issued at par. Interest on the 6.75% Notes is payable semi-annually in February and August and is guaranteed by substantially all of our subsidiaries. We may redeem the 6.75% Notes, in whole or in part, at any time on or after August 1, 2015, at redemption prices of 103.375% of the principal amount as of August 1, 2015 declining to 100.0% on August 1, 2018 and thereafter. Before August 1, 2013, we may redeem up to 35% of the original aggregate principal amount of the 6.75% Notes at a redemption price equal to 106.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that at least 65% of the original aggregate principal amount of the 6.75% 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. We used $287.1 million of the proceeds to repay outstanding borrowings under our credit facility and $204.2 million to redeem our 7.375% senior subordinated notes due 2013.

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

Early Extinguishment of Debt

In August 2010, we redeemed our 7.375% senior subordinated notes due 2013 at a redemption price equal to 101.229%. We recorded a loss on extinguishment of debt of $5.4 million including the transaction call premium costs as well as the expensing of related deferred financing cost on the repurchased debt.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries of our senior subordinated notes are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.

Debt Covenants and Maturity

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 4.0 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 December 31, 2010.

Following is the principal maturity schedule for the long-term debt outstanding as of December 31, 2010 (in thousands):


	Year Ended December 31,
2011	$	—
2012		274,000
2013		—
2014		—
2015		150,000
2016		249,682
Thereafter		1,286,854

	$	1,960,536

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 December 31, 2010, we were in compliance with these covenants.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2010

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATION

(8) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts 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. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2010 and 2009 is as follows (in thousands):


	2010			2009
Beginning of period	$	78,812		$	83,457

Liabilities incurred		1,562			1,622
Acquisitions		556			—
Liabilities settled		(2,605	)		(724	)
Disposition of wells		(12,891	)		(15,946	)
Accretion expense		5,320			5,893
Change in estimate		(8,081	)		4,510

End of period		62,673			78,812


Less current portion		(4,020	)		(2,446	)


Long-term asset retirement obligations	$	58,653		$	76,366

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying statements of operations.

Capital Stock

12 Months Ended

Dec. 31, 2010

Capital Stock [Abstract]

CAPITAL STOCK

(9) CAPITAL STOCK

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2008:


	Year Ended December 31,
	2010		2009		2008
Beginning balance		158,118,937		155,375,487		149,511,997
Public offerings		—		—		4,435,300
Shares issued in lieu of cash bonuses		—		184,926		—
Stock options/SARs exercised		991,988		1,384,861		1,339,536
Restricted stock grants		405,127		413,353		167,054
Issued for acreage purchases		380,229		743,737		—
Treasury shares		12,771		16,573		(78,400	)

Ending balance		159,909,052		158,118,937		155,375,487

Treasury Stock

In 2008, the Board of Directors approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. During 2008, we repurchased 78,400 shares of common stock an average price of $41.11 for a total of $3.2 million. As of December 31, 2010, we have $6.8 million remaining authorization to repurchase shares.

Shelf Registration Statement

In June 2009, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including a reduction of bank debt. Also in June 2009, we issued a $200.0 million registration statement where we may, from time to time, sell shares of our common stock in connection with an acquisition or business combination. As of December 31, 2010, we have $156.4 million remaining under this registration statement.

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2010, 2009 and 2008. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on our financial condition, earnings and cash flow from operations, level of capital expenditures, our future business prospects and other matters our Board of Directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations. Dividends are limited to our legally available funds.

Derivative Activities

12 Months Ended

Dec. 31, 2010

Derivative Activities [Abstract]

DERIVATIVE ACTIVITIES

(10) 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 and collar 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. In third quarter 2010, we also entered into call option derivative contracts under which we sold call options on crude oil in exchange for a cash premium received from the counterparty. At the time of settlement of these monthly call options, if the market price exceeds the fixed price of the call option, we will pay the counterparty such excess and if the market price settles below the fixed price of the call option, no payment is due from either party. At December 31, 2010, we had collars covering 192.8 Bcf of gas at weighted average floor and cap prices of $5.54 to $6.43 per mcf and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 to $80.00 per barrel. We also had sold call options for 3.7 million barrels of oil at a weighted average price of $82.31. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a net unrealized pre-tax gain of $118.0 million at December 31, 2010. These contracts expire monthly through December 2012. We currently have not entered into any NGL derivative contracts. The following table sets forth the derivative volumes by year as of December 31, 2010:


			Weighted
Period	Contract Type	Volume Hedged	Average Hedge Price
Natural Gas
2011	Collars	408,200 Mmbtu/day	$5.56– $6.48
2012	Collars	119,641 Mmbtu/day	$5.50– $6.25

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

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is 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 our derivatives that qualify for hedge accounting are recorded as a component of 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. As of December 31, 2010, an unrealized pre-tax derivative gain of $111.1 million was recorded in AOCI. This gain will be reclassified into earnings as a gain of $104.3 million in 2011 and a gain of $6.8 million in 2012 as the contracts settle. The actual reclassification to earnings will be based on market prices at the contract settlement date. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings in derivative fair value income.

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 $64.8 million of gains in 2010 compared to gains of $203.1 million in 2009 and losses of $63.6 million in 2008 related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value income in the accompanying 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. Derivative fair value income for the year ended December 31, 2010 includes ineffective gains (unrealized and realized) of $2.0 million compared to $3.1 million in 2009 and $3.1 million in 2008.

In addition to the collars above, we have entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $352,000 at December 31, 2010.

Derivative fair value income

The following table presents information about the components of derivative fair value income in the three-year period ended December 31, 2010 (in thousands):


	2010			2009			2008
Change in fair value of derivatives that do not qualify for hedge accounting ^{(a) (c)}	$	(2,086	)	$	(115,909	)	$	85,594
Realized gain (loss) on settlement—natural gas ^(a) ^(b)		35,988			171,998			(1,383	)
Realized gain (loss) on settlement—oil ^{(a) (b)}		—			7,304			(15,431	)
Realized gain on early settlement of oil derivatives ^(c)		15,697			—			—
Hedge ineffectiveness—realized		(352	)		4,749			1,386
—unrealized ^(c)		2,387			(1,696	)		1,695

Derivative fair value income	$	51,634		$	66,446		$	71,861


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

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

^(c)		Not included in realized prices.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2010 and 2009 is summarized below (in thousands). As of December 31, 2010, we are conducting derivative activities with nine financial institutions, all of which 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. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty.


	December 31,
	2010			2009
Derivative assets:
Natural gas—collars	$	163,354		$	26,649
—basis swaps		—			(1,063	)
Crude oil—collars		—			66
—call options		(31,904	)		—

	$	131,450		$	25,652


Derivative liabilities:
Natural gas—collars	$	27,032		$	2,020
—basis swaps		(352	)		(16,779	)
Crude oil—collars		(12,051	)		—
—call options		(28,393	)		—

	$	(13,764	)	$	(14,759	)

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 the accompanying consolidated balance sheets (in thousands):


	December 31, 2010								December 31, 2009
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying		Carrying			Net Carrying			Carrying		Carrying			Net Carrying
	Value		Value			Value			Value		Value			Value
Derivatives that qualify for cash flow hedge accounting :
Collars ^(a)	$	173,128	$	—		$	173,128		$	22,062	$	—		$	22,062

	$	173,128	$	—		$	173,128		$	22,062	$	—		$	22,062


Derivatives that do not qualify for hedge accounting :
Collars ^(a)	$	17,259	$	(12,052	)	$	5,207		$	6,673	$	—		$	6,673
Call options ^(a)		—		(60,297	)		(60,297	)		—		—			—
Basis swaps ^(a)		—		(352	)		(352	)		65		(17,907	)		(17,842	)

	$	17,259	$	(72,701	)	$	(55,442	)	$	6,738	$	(17,907	)	$	(11,169	)


^(a)		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 in the accompanying consolidated balance sheets are summarized below:


	Year Ended December 31,
							Realized Gain
	Change in Hedge						Reclassified from OCI
	Derivative Fair Value						into Revenue ^(a)
	2010			2009			2010			2009
Collars	$	165,642		$	91,059		$	64,772		$	203,119
Income taxes		(64,662	)		(34,180	)		(24,841	)		(75,154	)

	$	100,980		$	56,879		$	39,931		$	127,965


^(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 on our consolidated statement of operations is summarized below:


	Year Ended December 31,
	Gain (Loss) Recognized in								Gain (Loss) Recognized in							Derivative Fair Value
	Income (Non-hedge Derivatives)								Income (Ineffective Portion)							Income
	2010			2009			2008		2010		2009		2008			2010			2009			2008
Swaps	$	—		$	63,755		$	14,395	$	—	$	—	$	(438	)	$	—		$	63,755		$	13,957
Collars		65,996			33,859			33,119		2,035		3,053		3,519			68,031			36,912			36,638
Call options		(15,895	)		—			—		—		—		—			(15,895	)		—			—
Basis swaps		(502	)		(34,221	)		21,266		—		—		—			(502	)		(34,221	)		21,266

Total	$	49,599		$	63,393		$	68,780	$	2,035	$	3,053	$	3,081		$	51,634		$	66,446		$	71,861

Fair Value Measurements

12 Months Ended

Dec. 31, 2010

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

(11) 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 significantly 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 recurring 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 tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):


	Fair Value Measurements at December 31, 2010 Using:
	Quoted Prices in		Significant
	Active Markets		Other			Significant		Total Carrying
	for Identical		Observable			Unobservable		Value as of
	Assets		Inputs			Inputs		December 31,
	(Level 1)		(Level 2)			(Level 3)		2010
Trading securities held in the deferred compensation plans	$	47,794	$	—		$	—	$	47,794

Derivatives—collars		—		178,335			—		178,335
—call options		—		(60,297	)		—		(60,297	)
—basis swaps		—		(352	)		—		(352	)


	Fair Value Measurements at December 31, 2009 Using:
	Quoted Prices in		Significant
	Active Markets		Other			Significant		Total Carrying
	for Identical		Observable			Unobservable		Value as of
	Assets		Inputs			Inputs		December 31,
	(Level 1)		(Level 2)			(Level 3)		2009
Trading securities held in the deferred compensation plans	$	43,554	$	—		$	—	$	43,554

Derivatives—collars		—		28,735			—		28,735
—basis swaps		—		(17,842	)		—		(17,842	)

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2010 market value. 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 the 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 the accompanying statement of operations. For the year ended December 31, 2010, interest and dividends were $864,000 and mark-to-market was a gain of $11.5 million. For the year ended December 31, 2009, interest and dividends were $487,000 and the mark-to-market was a gain of $10.4 million. For the year ended December 31, 2008, interest and dividends were $1.5 million and the mark-to-market was a loss of $19.4 million.

Fair Values-Non recurring

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 and 2009 due to reductions in estimated reserves and natural gas prices. Additionally, while our Barnett properties did not meet held for sale criteria as of December 31, 2010, our analysis reflected undiscounted cash flows for these properties that were less than their carrying value. We therefore compared the carrying value of the Barnett properties to the estimated fair value of the properties and recognized an impairment charge of $463.2 million in the fourth quarter of 2010. The fair value of our Barnett properties considered the potential sale of these properties in addition to using an income approach with internal estimates which included reserve quantities, forward natural gas prices, anticipated drilling and operating costs and discount rates, which are Level 3 inputs. The fair value of our onshore Gulf Coast assets in 2010 and our Michigan assets in 2009 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 and an impairment of $930,000 in 2009 on our Michigan proved properties.

In 2009, our investment in Whipstock Natural gas Services, LLC was evaluated for impairment due to reductions in business activity and continued losses. The fair value of this investment was measured using an income approach based upon internal estimates of business activity, prices and discount rates, which are Level 3 inputs. Based on this analysis, we determined our equity investment was not recoverable and an impairment of $9.0 million was recorded.

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


	Year Ended December 31,
	2010				2009
					Fair
	Fair Value		Impairment		Value		Impairment
Natural gas and oil properties	$	851,988	$	469,749	$	1,244	$	930
Equity investments	$	—	$	—	$	2,895	$	8,950

On February 28, 2011 we announced that we entered into a definitive agreement to sell our Barnett properties and certain derivative contracts, for a price of $900.0 million, subject to typical post-closing adjustments, with an anticipated closing date of April 29, 2011. The basis of the asset group, which excludes the derivative contracts being sold, was approximately $835.0 million, net of the $463.2 million impairment charge noted above. The completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance that the sale will be completed or that the sales price won’t change. But based on the current purchase and sale agreement, we expect these assets will be presented as assets held-for-sale in the first quarter 2011.

Fair Values — Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2010 and 2009 (in thousands):


	December 31, 2010						December 31, 2009
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
Assets:
Commodity swaps, collars and call options	$	131,450		$	131,450		$	25,652		$	25,652
Marketable securities ^(a)		47,794			47,794			43,554			43,554

Liabilities:
Commodity swaps, collars and call options		(13,764	)		(13,764	)		(14,759	)		(14,759	)
Long-term debt ^(b)		(1,960,536	)		(2,055,813	)		(1,707,833	)		(1,842,625	)


^(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.

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense.

Concentration of Credit Risk

As of December 31, 2010, our primary concentration of credit risks are the risks of collecting accounts receivable and the risk of counterparties failure to perform under derivative obligations. 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 necessary to limit risk of loss. Our allowance for uncollectible receivables was $5.0 million at December 31, 2010 and $2.2 million at December 31, 2009. As of December 31, 2010, our derivative contracts consist of collars and call options. Our exposure is diversified primarily among major investment grade financial institutions the majority of which we have master netting agreements with that provide for offsetting payables against receivables from separate derivative contracts. Currently our derivative counterparties include nine financial institutions, all of which are secured lenders in our bank credit facility. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date.

Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2010

Stock-Based Compensation Plans [Abstract]

STOCK-BASED COMPENSATION PLANS

(12) STOCK-BASED COMPENSATION PLANS

Description of the Plans

The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the Compensation Committee of the Board of Directors to grant, among other things, stock options, stock appreciation rights and restricted stock awards to employees and directors. The 2004 Non-Employee Director Stock Option Plan (the “Director Plan”) allows such grants to our non-employee directors of our Board of Directors. The 2005 Plan was approved by stockholders in May 2005 and replaced our 1999 Stock Option Plan. No new grants have been made from the 1999 Stock Option Plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares (15.0 million less the 2.2 million shares issued under the 1999 Stock Option Plan before May 18, 2005, the effective date of the 2005 Plan and less the 7.2 million shares issuable pursuant to awards under the 1999 Stock Option Plan outstanding as of the effective date of the 2005 Plan) plus (ii) the number of shares subject to 1999 Stock Option Plan awards outstanding at May 18, 2005 that subsequently lapse or terminate without the underlying shares being issued plus (iii) subsequent shares approved by the shareholders. The Director Plan was approved by stockholders in May 2004 and no more than 450,000 shares of common stock may be issued under the Plan.

Stock-based awards under the Plans

Stock options represent the right to purchase shares of stock in the future at the fair value of the stock on the date of grant. Most stock options granted under our stock option plans vest over a three-year period and expire five years from the date they are granted. Beginning in 2005, we began granting stock appreciation rights (“SARs”) to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted.

The Compensation Committee grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock and receive dividends thereon. All restricted shares that are granted are placed in our deferred compensation plan and employees are allowed to take withdrawals either in cash or in stock. Restricted stock awards are classified as a liability award and are remeasured at fair value each reporting period. This mark-to-market is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used unissued shares of stock when restricted stock is issued. However, we also utilize treasury shares when available.

In 2009, as part of the closure of our Houston office, unvested SARs and restricted stock grants were modified and fully vested effective with the closing of the office on November 1, 2009. The incremental compensation cost of this modification was $332,000. As part of the sale of our Ohio properties in 2010, unvested SARs and restricted stock grants were modified and fully vested effective with the date of the sale. The incremental compensation cost of this modification was $2.8 million. These modification costs are reported in termination costs in the accompanying consolidated statements of operations.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock grants and SARs expense. In 2010, stock-based compensation was allocated to operating expense ($2.3 million), exploration expense ($4.2 million), general and administrative expense ($34.2 million) and termination costs ($2.8 million) for a total of $44.7 million. In 2009, stock-based compensation was allocated to operating expense ($2.6 million), exploration expense ($4.7 million) general administrative expense ($33.3 million) and termination costs ($332,000) for a total of $41.8 million. In 2008, stock-based compensation was allocated to direct operating expense ($2.8 million), exploration expense ($4.1 million) and general and administrative expense ($23.8 million) for a total of $31.2 million. Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. For the year ended December 31, 2010, cash received upon exercise of stock options/SARs awards was $5.9 million. Due to the net operating loss carryforward for tax purposes, tax benefits realized for deductions that were in excess of the stock-based compensation expense were not recognized.

Stock and Option Plans

We have two active equity-based stock plans, the 2005 Plan and the Director Plan. Under these plans, incentive and non-qualified stock options, stock appreciation rights, restricted stock, phantom stock and various other awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors. All awards granted under these plans have been issued at prevailing market prices at the time of the grant. Since the middle of 2005, only SARs have been granted under the plans to limit the dilutive impact of our equity plans. Of the 6.5 million grants outstanding at December 31, 2010, 785,000 of the grants relate to stock options with the remainder of 5.7 million grants relating to SARs. Information with respect to stock option and SARs activities is summarized below:


				Weighted
				Average
	Shares			Exercise Price
Outstanding at December 31, 2007		7,772,325		$	17.95
Granted		1,159,649			63.18
Exercised		(1,590,390	)		12.24
Expired/forfeited		(92,918	)		40.82

Outstanding at December 31, 2008		7,248,666			26.15
Granted		1,714,165			36.90
Exercised		(1,717,584	)		14.31
Expired/forfeited		(90,535	)		40.73

Outstanding at December 31, 2009		7,154,712			31.38
Granted		1,394,136			46.09
Exercised		(1,883,091	)		20.49
Expired/forfeited		(203,918	)		48.18

Outstanding at December 31, 2010		6,461,839		$	37.20

The following table shows information with respect to stock options and SARs outstanding and exercisable at December 31, 2010:


	Outstanding						Exercisable
			Weighted-
			Average		Weighted-				Weighted
			Remaining		Average				Average
			Contractual		Exercise				Exercise
Range of Exercise Prices	Shares		Life		Price		Shares		Price
$ 1.29– $9.99		770,056		1.10	$	3.55		770,056	$	3.55
10.00–19.99		15,435		4.73		19.63		15,435		19.63
20.00–29.99		780,219		0.26		24.32		780,219		24.32
30.00–39.99		1,958,221		1.94		34.49		1,373,383		34.60
40.00–49.99		1,938,906		3.90		44.69		293,309		42.36
50.00–59.99		634,837		1.94		58.32		404,805		58.53
60.00–69.99		18,927		2.42		65.56		11,356		65.56
70.00–75.00		345,238		2.29		75.00		224,285		75.00

Total		6,461,839		2.25	$	37.20		3,872,848	$	31.82

Stock Appreciation Right Awards

During 2010, 2009 and 2008, we granted SARs to officers, non-officer employees and directors. The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:


	2010			2009			2008
Weighted average exercise price per share	$	46.09		$	36.90		$	63.18
Expected annual dividends per share		0.35	%		0.44	%		0.26	%
Expected life in years		3.6			3.5			3.5
Expected volatility		49	%		58	%		41	%
Risk-free interest rate		1.6	%		1.5	%		2.4	%
Weighted average grant date fair value of SARs granted	$	17.01		$	15.42		$	20.58

The dividend yield is based on the current annual dividend at the time of grant. The expected term was based on the historical exercise activity. The volatility factors are based on a combination of both the historical volatilities of the stock and implied volatility of traded options on our common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options.

The total intrinsic value (the difference in value between exercise and market price) of stock options and SARs exercised during the years ended December 31, 2010 was $50.6 million compared to $50.9 million in 2009 and $67.9 million in 2008. As of December 31, 2010, the aggregate intrinsic value of the awards outstanding was $71.0 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option/SARs awards currently exercisable was $63.5 million and 1.3 years. As of December 31, 2010, the number of fully vested awards and awards expected to vest was 6.3 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $36.91 and 2.2 years and the aggregate intrinsic value was $70.4 million. As of December 31, 2010, unrecognized compensation cost related to the awards was $25.5 million, which is expected to be recognized over a weighted average period of 1.8 years.

Restricted Stock Awards

In 2010, we granted 413,000 shares of restricted stock grants as compensation to directors and employees at an average price of $45.83. The restricted stock grants included 21,000 issued to directors which vest immediately and 392,000 to employees with vesting generally over a three-year period. In 2009, we granted 686,000 shares of restricted stock grants as compensation to directors and employees at an average price of $39.99. The restricted stock grants included 22,700 issued to directors, which vest immediately and 663,300 to employees with vesting generally over a three-year period. In 2008, we issued 362,000 shares of restricted stock grants as compensation to directors and employees at an average price of $63.00. The restricted stock grants included 14,400 issued to directors, which vest immediately and 347,600 to employees with vesting generally over a three-year period. We recorded compensation expense for restricted stock grants of $20.5 million in the year ended December 31, 2010 compared to $19.7 million in 2009 and $14.7 million in 2008. As of December 31, 2010, there was $23.3 million of unrecognized compensation related to restricted stock awards expected to be recognized over a weighted average period of 1.8 years. All of our restricted stock grants are held in our deferred compensation plan. All restricted stock awards are classified as liability award and are remeasured at fair value each reporting period. This mark-to-market is reported in the deferred compensation expense in our consolidated statement of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan was $5.2 million in 2010.

A summary of the status of our non-vested restricted stock outstanding at December 31, 2010 is summarized below:


				Weighted
				Average Grant
	Shares			Date Fair Value
Non-vested shares outstanding at December 31, 2007		563,660		$	30.42
Granted		362,313			63.00
Vested		(438,058	)		37.54
Forfeited		(14,368	)		38.87


Non-vested shares outstanding at December 31, 2008		473,547			48.50
Granted		685,578			39.99
Vested		(521,536	)		40.91
Forfeited		(10,400	)		40.83


Non-vested shares outstanding at December 31, 2009		627,189			45.64
Granted		413,422			45.83
Vested		(439,361	)		46.90
Forfeited		(18,499	)		46.04

Non-vested shares outstanding at December 31, 2010		582,751		$	44.81

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. Prior to 2008, we made discretionary contributions of our common stock to the 401(k) Plan annually. Beginning in 2008, we began matching up to 6% of salary in cash. All our contributions become fully vested after the individual employee has two years of service with us. In 2010, we contributed $3.1 million to the plan compared to $3.2 million in 2009 and $2.7 million in 2008. Employees have a variety of investment options in the 401(k) benefit plan.

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 in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of all of the plans 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 or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and 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 our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market income of $10.2 million in 2010 compared to mark-to-market loss of $31.1 million in 2009 and mark-to-market income of $24.7 million in 2008. The Rabbi Trust held 2.9 million shares (2.3 million of vested shares) of Range stock at December 31, 2010 compared to 2.7 million shares (2.1 million of vested shares) at December 31, 2009.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2010

Supplemental Cash Flow Information [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

(13) SUPPLEMENTAL CASH FLOW INFORMATION


	Year Ended December 31,
	2010			2009		2008
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(1,359	)	$	170	$	4,298
Interest paid		116,766			108,685		93,954

Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net		(6,523	)		6,131		4,647
Unproved property purchased with stock		20,000			33,726		—
Shares issued in lieu of bonuses		—			6,312		—

Commitments and Contingencies

12 Months Ended

Dec. 31, 2010

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

(14) COMMITMENTS AND CONTINGENCIES

Litigation

We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

Lease Commitments

We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $18.5 million in 2010 compared to $18.8 million in 2009 and $15.4 million in 2008. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands):


	Operating
	Lease
	Obligations
2011	$	9,913
2012		10,054
2013		7,067
2014		6,395
2015		6,368
Thereafter		27,833
Sublease rentals		(615	)

	$	67,015

Transportation Contracts

We have entered firm transportation contracts with various pipelines. Under these contracts, we are obligated to transport minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As of December 31, 2010, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):


	Transportation
	Commitments
2011	$	68,587
2012		65,824
2013		64,794
2014		61,351
2015		59,870
Thereafter		381,697

	$	702,123

In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2030 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreements call for total incremental increases of 683,000 Mmbtu per day over the 284,905 Mmbtu per day at December 31, 2010. These increases, which are contingent on certain pipeline modifications are for 350,000 Mmbtu per day in February 2011, 150,000 Mmbtu per day in September 2011, 108,000 Mmbtu per day in November 2012 and 75,000 Mmbtu per day in November 2013.

Drilling Contracts

As of December 31, 2010, we have contracts with drilling contractors to use eight drilling rigs with terms of up to three years and minimum future commitments of $72.9 million in 2011, $53.7 million in 2012, $14.7 million in 2013 and $896,000 in 2014. Six rigs were custom built for our Marcellus Shale program. Early termination of these contracts at December 31, 2010 would have required us to pay maximum penalties of $93.4 million. We do not expect to pay any early termination penalties related to these contracts.

Delivery Commitments

Under a sales agreement, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale in the Fort Worth Basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2010, remaining volumes to be delivered under this commitment are approximately 24.6 Bcf.

Other

We have agreements in place to purchase seismic data. These agreements total $11.8 million in 2011, $6.0 million in 2012 and $645,000 in 2013. We also have a two-year agreement to lease equipment, material and labor for hydraulic fracturing services for $48.0 million in 2011 and $40.0 million in 2012. We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Major Customers	12 Months Ended
Major Customers	Dec. 31, 2010
Major Customers [Abstract]
MAJOR CUSTOMERS	(15) MAJOR CUSTOMERS We market our production on a competitive basis. Natural gas is sold under various types of contracts including month-to-month, and one to five year contracts. Pricing on the month-to-month and short-term contracts is based largely on NYMEX, with fixed or floating basis. For one to five-year contracts, we sell our natural gas on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local indices. We sell our oil under contracts ranging in terms from month-to-month, up to as long as one year. The price for oil is generally equal to a posted price set by major purchasers in the area or is based on NYMEX pricing or fixed pricing, adjusted for quality and transportation differentials. We sell to natural gas and oil purchasers on the basis of price, credit quality and service reliability. Our NGL production is primarily sold to natural gas processors. For the year ended December 31, 2010, we had no customers that accounted for 10% or more of total oil and gas revenues. For the year ended December 31, 2009, we had no customers that accounted for 10% or more of total oil and gas revenues. For the year ended December 31, 2008, one customer accounted for 10% or more of total oil and gas revenues. We believe that the loss of any one customer would not have a material adverse effect on our results.

Equity Method Investments	12 Months Ended
Equity Method Investments	Dec. 31, 2010
Equity Method Investments [Abstract]
EQUITY METHOD INVESTMENTS	(16) EQUITY METHOD INVESTMENTS We account for our investments in entities over which we have significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, we record our proportionate share of net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. We also evaluate our equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other than temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. For our investment in Whipstock, these indicators were present during the year ended December 31, 2009 and as a result, we recognized impairment charges of $9.0 million related to our equity method investment in 2009. *Investment in Whipstock Natural Gas Services, LLC* In 2006, we acquired a 50% interest in Whipstock Natural Gas Services, LLC (“Whipstock”), an unconsolidated investee in the business of providing oil and gas drilling equipment, well servicing rigs and equipment, and other well services in Appalachia. On the acquisition date, we contributed cash of $11.7 million representing the fair value of 50% of the membership interest in Whipstock. Whipstock follows a calendar year basis of financial reporting consistent with us and our equity in Whipstock’s earnings from the acquisition date is included in other revenue in the accompanying statements of operations for 2010, 2009 and 2008. During the year ended December 31, 2009, we received $301,000 in cash distributions from Whipstock. During the year ended December 31, 2008, we received cash distributions from Whipstock of $1.8 million. In determining our proportionate share of the net earnings of Whipstock, certain adjustments are required to be made to Whipstock’s reported results to eliminate the profits recognized by Whipstock for services provided to us. For the year ended December 31, 2010, our equity in the losses of Whipstock totaled $2.2 million compared to losses of $13.1 million in 2009 and losses of $479,000 in 2008. In 2010, equity in the losses of Whipstock was reduced by $1.1 million to eliminate the profit on services provided to us compared to $422,000 in 2009 and $1.8 million in 2008. In addition, equity in 2009 losses of Whipstock reflected a $9.0 million impairment charge due to an other than temporary decline in the fair value of our investment. Our fair value determination was based on a discounted cash flow analysis which qualifies as a level 3 fair value measurement in the fair value hierarchy table. Our net book value in this equity investment was $1.7 million at December 31, 2010. Range and Whipstock have entered into an agreement whereby Whipstock will provide us with the right of first refusal such that we will have the opportunity to secure services from Whipstock in preference to and in advance of Whipstock entering into additional commitments for services with other customers. All services provided to us are based on Whipstock’s usual and customary terms. *Investment in Nora Gathering, LLC* In May 2007, we completed the initial closing of a joint development arrangement with EQT Corporation (“EQT”). Pursuant to the terms of the arrangement, Range and EQT (“the parties”) agreed to, among other things, form a new pipeline and natural gas gathering operations entity, Nora Gathering, LLC (“NGLLC”). NGLLC is an unconsolidated investee created by the parties for the purpose of conducting pipeline, natural gas gathering, and transportation operations associated with the parties’ collective interests in properties in the Nora Field. In connection with the acquisition, we contributed cash of $94.7 million for a 50% membership interest in NGLLC. During 2010, Range and EQT made no additional contributions to fund the expansion of the Nora Field gathering system infrastructure compared to $6.4 million of additional capital in 2009. NGLLC follows a calendar year basis of financial reporting consistent with Range and our equity in NGLLC earnings from the acquisition date is included in other revenue in the accompanying statements of operations for 2010, 2009 and 2008. There were no dividends or partnership distributions received from NGLLC during the years ended December 31, 2010 or December 31, 2009. In determining our proportionate share of the net earnings of NGLLC, certain adjustments are required to be made to NGLLC’s reported results to eliminate the profits recognized by NGLLC included in the gathering and transportation fees charged to us on production in the Nora field. For the year ended December 31, 2010, our equity in the earnings of NGLLC of $684,000 reflects a reduction of $8.8 million to eliminate the profit on the gathering and transportation fees charged to us. For the year ended December 31, 2009 our equity in the losses of NGLLC of $629,600 reflects a reduction of $7.0 million to eliminate the profit on gathering and transportation fees charged to us. For the year ended December 31, 2008, our equity in the earnings of NGLLC of $261,000 reflects a reduction of $4.8 million to eliminate the profit on gathering and transportation fees charged to us. Our net book value in this equity investment was $153.4 million at December 31, 2010.

Office Closing and Exit Activities

12 Months Ended

Dec. 31, 2010

Office Closing and Exit Activities [Abstract]

OFFICE CLOSING AND EXIT ACTIVITIES

(17) OFFICE CLOSING AND EXIT ACTIVITIES

In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio. 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 by approximately $2.8 million.

In third quarter 2009, we announced the closing of our Gulf Coast area administrative and operations office in Houston, Texas. The properties are now operated from our Southwest area office in Fort Worth. The year ended December 31, 2009 includes $1.3 million of accrued severance, lease termination and accelerated vesting of SARs and restricted stock grants costs. Expenses related to lease termination and severance costs are included in termination costs in the accompanying consolidated statements of operations.

In fourth quarter 2009 we sold our natural gas properties in New York. We accrued $635,000 of severance costs related to this divestiture and the cost is included in termination costs in the accompanying consolidated statements of operations. The following table details our exit activities (in thousands):


	2010			2009
Beginning balance	$	1,568		$	—
Accrued one-time termination costs		5,138			1,895
Office lease		514			252
Payments		(6,128	)		(579	)

Ending balance	$	1,092		$	1,568

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2010

Selected Quarterly Financial Data [Abstract]

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(18) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years (in thousands).


	2010
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGL and oil sales	$	236,760		$	206,784		$	219,560		$	246,503		$	909,607
Transportation and gathering		2,093			674			(1,634	)		(65	)		1,068
Derivative fair value income (loss)		42,333			6,546			9,981			(7,226	)		51,634
Gain on the sale of assets		68,868			10,176			67			(1,514	)		77,597
Other		(1,575	)		637			(1,013	)		1,020			(931	)

Total revenue and other income		348,479			224,817			226,961			238,718			1,038,975


Costs and expenses:
Direct operating		31,040			29,775			34,287			36,500			131,602
Production and ad valorem taxes		8,070			8,090			8,873			8,619			33,652
Exploration		14,635			14,473			15,236			16,743			61,087
Abandonment and impairment of unproved properties		12,407			13,497			20,534			23,533			69,971
General and administrative		28,170			35,836			36,523			40,042			140,571
Termination costs		7,938			—			—			514			8,452
Deferred compensation plan		(5,712	)		(14,135	)		(5,347	)		14,978			(10,216	)
Interest expense		30,287			30,779			33,806			36,320			131,192
Loss on early extinguishment of debt		—			—			5,351			—			5,351
Depletion, depreciation and amortization		88,626			90,997			91,768			92,116			363,507
Impairment of proved properties		6,505			—			—			463,244			469,749

Total costs and expenses		221,966			209,312			241,031			732,609			1,404,918


Income (loss) before income taxes		126,513			15,505			(14,070	)		(493,891	)		(365,943	)

Income tax expense (benefit)
Current		—			—			(10	)		(826	)		(836	)
Deferred		48,934			6,453			(5,892	)		(175,346	)		(125,851	)

		48,934			6,453			(5,902	)		(176,172	)		(126,687	)


Net income (loss)	$	77,579		$	9,052		$	(8,168	)	$	(317,719	)	$	(239,256	)


Income (loss) per common share:
Basic	$	0.50		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.53	)


Diluted	$	0.48		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.53	)


	2009
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGL and oil sales	$	203,189		$	192,523		$	202,122		$	242,087		$	839,921
Transportation and gathering		(505	)		2,152			2,444			(3,605	)		486
Derivative fair value income (loss)		75,547			(9,856	)		(482	)		1,237			66,446
Gain on the sale of assets		36			(29	)		32			10,374			10,413
Other		(1,830	)		(4,358	)		(475	)		(3,262	)		(9,925	)

Total revenue and other income		276,437			180,432			203,641			246,831			907,341


Costs and expenses:
Direct operating		35,541			34,828			31,111			31,731			133,211
Production and ad valorem taxes		8,257			7,564			7,600			8,748			32,169
Exploration		13,339			11,368			10,902			10,876			46,485
Abandonment and impairment of unproved properties		19,572			40,954			24,053			28,959			113,538
General and administrative		24,910			29,103			29,928			31,378			115,319
Termination costs		—			—			840			1,639			2,479
Deferred compensation plan		12,434			756			16,445			1,438			31,073
Interest expense		26,629			29,555			30,633			30,550			117,367
Depletion, depreciation and amortization		84,320			88,713			97,208			103,261			373,502
Impairment of proved properties		—			—			—			930			930

Total costs and expenses		225,002			242,841			248,720			249,510			966,073


Income (loss) before income taxes		51,435			(62,409	)		(45,079	)		(2,679	)		(58,732	)

Income tax expense (benefit)
Current		—			619			(695	)		(560	)		(636	)
Deferred		18,827			(23,145	)		(14,566	)		14,658			(4,226	)

		18,827			(22,526	)		(15,261	)		14,098			(4,862	)


Net income (loss)	$	32,608		$	(39,883	)	$	(29,818	)	$	(16,777	)	$	(53,870	)


Income (loss) per common share:
Basic	$	0.21		$	(0.26	)	$	(0.19	)	$	(0.11	)	$	(0.35	)


Diluted	$	0.21		$	(0.26	)	$	(0.19	)	$	(0.11	)	$	(0.35	)

Principal Unconsolidated Investees (unaudited)


Company	December 31, 2010 Ownership			Activity
Whipstock Natural Gas Services, LLC		50	%	Drilling services
Nora Gathering, LLC		50	%	Gas gathering and transportation

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities

12 Months Ended

Dec. 31, 2010

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities [Abstract]

SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES

(19)

SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

Our gas natural and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization ^(a)


	December 31,
	2010			2009			2008
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	5,749,620		$	5,534,204		$	5,271,020
Unproved properties		811,834			774,503			757,960

Total		6,561,454			6,308,707			6,028,980
Accumulated depreciation, depletion and amortization		(1,639,397	)		(1,409,888	)		(1,186,934	)

Net capitalized costs	$	4,922,057		$	4,898,819		$	4,842,046


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

Costs Incurred for Property Acquisition, Exploration and Development ^(a)


	Year Ended December 31,
	2010			2009		2008
	(in thousands)
Acquisitions:
Unproved leasehold	$	3,697		$	—	$	99,446
Proved oil and gas properties		130,767			—		251,471
Asset retirement obligations		556			—		251
Acreage purchases ^(b)		166,677			176,867		494,341
Development		784,153			497,702		729,268
Exploration:
Drilling		50,737			57,121		133,116
Expense		56,879			42,082		63,560
Stock-based compensation expense		4,209			4,817		4,130
Gas gathering facilities:
Development		20,726			29,524		47,056

Subtotal		1,218,401			808,113		1,822,639

Asset retirement obligations		(6,523	)		6,131		4,647


Total costs incurred	$	1,211,878		$	814,244	$	1,827,286


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

^(b)		2009 includes $20.0 million accrued for acreage purchases for which 380,229 shares were issued in January 2010. 2008 includes a single transaction to acquire Marcellus Shale acreage for $223.9 million.

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reserves of natural gas, natural gas liquids, crude oil and condensate are estimated by our engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

Recent SEC and FASB Rule-Making Activity

In December 2008, the SEC announced that it had approved revisions designed to modernize the natural gas and oil company reserves reporting requirements. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates for 2010 and 2009.

Reserve Estimation

At year-end 2010, the following independent petroleum consultants conducted a process review of our reserves: DeGolyer and MacNaughton (Southwest), H.J. Gruy and Associates, Inc. (Southwest) and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2010, these consultants collectively reviewed approximately 90% of our proved reserves. A copy of the summary reserve report of each of these independent petroleum consultants is included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for their reserves review process. Throughout the year, our technical team meets regularly with representatives of each of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any internally estimated significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest; natural gas and oil production; well test data; commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering. In some cases, additional meetings are held to review additional reserve work performed by the technical teams related to any identified reserve differences.

Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this Annual Report on Form 10-K are those reserves estimated by our employees. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering, who reports directly to our President and Chief Operating Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

The SEC defines proved reserves as those volumes of natural gas, natural gas liquids, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances, justify a longer time.

Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, and, especially in the case of natural gas, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

The average realized prices used at December 31, 2010 to estimate reserve information were $72.51 per barrel of oil, $39.14 per barrel for natural gas liquids and $3.70 per mcf for gas, using benchmark prices (NYMEX) of $79.81 per barrel and $4.38 per Mmbtu. The average realized prices used at December 31, 2009 to estimate reserve information were $54.65 per barrel of oil, $34.05 per barrel for natural gas liquids and $3.19 per mcf for gas, using benchmark prices (NYMEX) of $60.85 per barrel and $3.87 per Mmbtu. The average realized prices used at December 31, 2008 to estimate reserve information were $42.76 per barrel of oil, $25.00 per barrel for natural gas liquids and $5.23 per mcf for gas, using benchmark prices (NYMEX) of $44.60 per barrel and $5.71 per Mmbtu.


										Natural Gas
	Natural Gas			NGLs			Crude Oil			Equivalents ^(a)
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe)
Proved developed and undeveloped reserves:
Balance, December 31, 2007		1,832,797			17,748			48,912			2,232,762
Revisions		(23,397	)		1,791			(4,946	)		(42,333	)
Extensions, discoveries and additions		423,354			5,643			10,198			518,404
Purchases		95,262			53			—			95,578
Property sales		(147	)		—			(1,592	)		(9,701	)
Production		(114,323	)		(1,386	)		(3,085	)		(141,145	)


Balance, December 31, 2008		2,213,546			23,849			49,487			2,653,565
Revisions		(37,497	)		8,434			(1,536	)		3,890
Extensions, discoveries and additions		620,114			21,492			3,479			769,939
Purchases		—			—			—			—
Property sales		(50,797	)		—			(14,791	)		(139,543	)
Production		(130,649	)		(2,187	)		(2,557	)		(159,112	)


Balance, December 31, 2009		2,614,717			51,588			34,082			3,128,739
Revisions		3,599			26,832			(2,672	)		148,558
Extensions, discoveries and additions		1,089,632			48,792			4,663			1,410,359
Purchases		124,981			—			—			124,981
Property sales		(124,369	)		—			(10,865	)		(189,558	)
Production		(142,034	)		(4,490	)		(1,969	)		(180,789	)


Balance, December 31, 2010		3,566,526			122,722			23,239			4,442,290


Proved developed reserves:
December 31, 2008		1,337,978			16,398			32,611			1,632,032

December 31, 2009		1,445,705			26,205			20,626			1,726,696

December 31, 2010		1,762,766			53,071			17,050			2,183,488


Proved undeveloped reserves:
December 31, 2008		875,567			7,451			16,876			1,021,531

December 31, 2009		1,169,012			25,382			13,457			1,402,043

December 31, 2010		1,803,760			69,651			6,189			2,258,802


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

The following details the changes in proved undeveloped reserves for 2010 (Mmcfe):


Beginning proved undeveloped reserves-2009	1,402,043
Undeveloped reserves transferred to developed	(191,220	)
Revisions	(75,685	)
Purchases/sales	(25,643	)
Extension and discoveries	1,149,307

Ending proved undeveloped reserves-2010	2,258,802

During 2010, various exploration and development drilling evaluations were completed. Approximately $192.0 million was spent during 2010 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $476.9 million in 2011, $830.8 million in 2012 and $924.8 million in 2013. Included in proved undeveloped reserves at December 31, 2010 are approximately 2,388 Mmcfe of reserves (less than 1% of total proved undeveloped reserves) that have been reported for five or more years. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2015.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas and oil reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs and crude oil, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

	1.		Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

	2.		Prior to 2009, estimated future cash inflows were calculated by applying current year-end prices of natural gas and oil relating to our proved reserves to the quantities of those reserves produced in each future year. For 2009 and 2010, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

	3.		Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.

	4.		The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows and excludes cash flows associated with hedges outstanding at each of the respective reporting dates.


	As of December 31,
	2010			2009
	(in thousands)
Future cash inflows	$	19,676,630		$	11,969,906
Future costs:
Production		(4,305,292	)		(3,371,762	)
Development		(2,855,407	)		(1,877,330	)


Future net cash flows before income taxes		12,515,931			6,720,814

Future income tax expense		(3,923,264	)		(1,767,965	)


Total future net cash flows before 10% discount		8,592,667			4,952,849

10% annual discount		(5,113,541	)		(2,861,760	)


Standardized measure of discounted future net cash flows	$	3,479,126		$	2,091,089

The following table summarizes changes in the standardized measure of discounted future net cash flows.


	As of December 31,
	2010			2009			2008
	(in thousands)
Beginning of period	$	2,091,089		$	2,581,380		$	3,666,363
Revisions of previous estimates:
Changes in prices		957,994			(992,809	)		(1,675,703	)
Revisions in quantities		190,874			4,124			(65,931	)
Changes in future development costs		(474,058	)		(375,344	)		(688,259	)
Accretion of discount		259,280			340,025			520,482
Net change in income taxes		(666,517	)		317,158			719,595
Purchases of reserves in place		160,580			—			148,857
Additions to proved reserves from extensions, discoveries and improved recovery		1,812,077			816,278			807,386
Production		(744,354	)		(673,907	)		(1,029,001	)
Development costs incurred during the period		298,624			316,523			333,979
Sales of natural gas and oil		(243,551	)		(147,942	)		(15,109	)
Timing and other		(162,912	)		(94,397	)		(141,279	)

End of period	$	3,479,126		$	2,091,089		$	2,581,380

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2010
Summary of Significant Accounting Policies (Policies) [Abstract]
Basis of Presentation and Principles of Consolidation	The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in other revenues in the accompanying consolidated statements of operations. All material intercompany balances and transactions have been eliminated.
Use of Estimates	The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas and oil reserves. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.
Reclassifications	Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation, which includes the reclassification of severance costs associated with the closing of our Houston office and the sale of our New York properties from direct operating expense, exploration expense and general and administrative expense to termination costs. The accompanying consolidated statements of operations also include the reclassification in all periods of the gain on sale of assets from other revenues and the reclassification of impairment of proved properties from depletion, depreciation and amortization. These reclassifications did not impact our net income or loss, stockholders’ equity or cash flows.
Income per Common Share	Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding. Diluted income (loss) per common share assumes issuance of stock compensation awards, provided the effect is not antidilutive.
Business Segment Information	We have evaluated how Range is organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, natural gas liquids (“NGLs”) and oil. We consider our gathering, processing and marketing functions as ancillary to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability without regard to individual areas or segments.
Revenue Recognition and Gas Imbalances	Natural gas, NGL and oil revenues are recognized when the products are sold and delivery to the purchaser has occurred. We recognize the cost of revenues, such as transportation and compression expense, as a reduction to revenue. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $5.0 million at December 31, 2010 compared to $2.2 million at December 31, 2009. During the year ended 2010, we recorded $3.6 million of bad debt expense compared to $1.4 million in the same period of the prior year. We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of the gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2009 were not significant. At December 31, 2010, we had recorded a net liability of $587,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.
Cash and Cash Equivalents	Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.
Marketable Securities	Holdings of equity securities held in our deferred compensation plans qualify as trading and are recorded at fair value. Investments in the deferred compensation plans are in mutual funds and consist of various publicly-traded mutual funds. These funds are made up of investments which include equities and money market instruments.
Inventories	Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market, on a first-in, first-out basis. Our inventory is primarily acquired for use in future drilling operations.
Oil and Gas Properties	We follow the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. NGLs and oil are converted to gas equivalent basis or mcfe at the rate of one barrel of oil equating to 6 mcf of natural gas. Depreciation, depletion and amortization of proved producing properties is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009. Accounting Standards Codification (ASC) 2010-3 clarified that the effect of the change in price encompassed in the new SEC rules was a change in accounting principle inseparable from a change in estimate for 2009 and was accounted for prospectively. For 2009, we estimated the effect of this change in estimate increased depletion, depreciation and amortization expense by approximately $3.4 million ($2.2 million after tax) primarily due to lower prices reflected in our estimated reserves. Our natural gas and oil producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. For additional information regarding 2010 and 2009 proved property impairments, see Note 11. Proceeds from the disposal of natural gas and oil producing properties that are part of an entire amortization group are credited to the net book value of their amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $811.8 million in 2010 compared to $774.5 million in 2009. We have recorded abandonment and impairment expense related to unproved properties of $70.0 million in 2010 compared to $113.5 million in 2009 and to $47.4 million in 2008.
Transportation and Field Assets	Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these pipeline systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. We receive third-party income for providing field service and certain transportation services, which is recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Buildings are depreciated over 10 to 15 years. Depreciation expense was $16.2 million in 2010 compared to $31.7 million in 2009 and $13.7 million in 2008. The fourth quarter 2009 includes accelerated depreciation expense of $10.3 million related to an interim processing plant in our Appalachian region that was dismantled in first quarter 2010 and replaced with permanent facilities.
Other Assets	The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2010 include $27.9 million of unamortized debt issuance costs, $47.8 million of marketable securities held in our deferred compensation plans and $9.3 million of other investments.
Stock-based Compensation Arrangements	The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period.
Derivative Financial Instruments and Hedging	All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. Through December 2010, 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 hedged transaction is probable to not occur, any unrealized gains or losses is recognized immediately in derivative fair value income in the accompanying consolidated statements of operations. During 2010, we recognized a gain of $11.6 million (pre-tax) compared to a gain of $5.4 million in 2009 and a loss of $583,000 in 2008 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives. We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas and oil production. Accordingly, we record changes in the fair value of our collar and call option contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets. Gains or losses on these collar and call options contracts are reclassified out of AOCI and into natural gas, NGL and oil sales when the underlying physical transaction occurs and the hedging contract is settled. Any hedge ineffectiveness associated with a contract qualifying and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income on the accompanying consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized). Realized and unrealized gains and losses on derivatives that are not designated as hedges (or “non-hedge derivatives”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value income in the accompanying consolidated statements of operations. We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreement that effectively fix our basis adjustments.
Asset Retirement Obligations	The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. The depreciation will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets.
Deferred Taxes	Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income including tax credits and operating loss carryforwards.
Amendment of variable interest accounting standards	Accounting standards for variable interest entities were amended by the Financial Accounting Standards Board (the “FASB”) in September 2009. The new accounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended accounting standard for variable interest entities requires reconsideration for determining whether an entity is a variable entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. The adoption of this guidance did not have an impact on our consolidated results of operations, financial position or cash flows.
Issuance of disclosures about fair value measurements	A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (a) the different classes of assets and liabilities measured at fair value, (b) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (c) the gross presentation of purchases, sales, issuances and settlements for the roll forward of Level 3 activity, and (d) the transfers in and out of Levels 1 and 2. We adopted all aspects of this standard in first quarter 2010. This adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows. See Note 11 for our disclosures about fair value measurements.
Amended guidance on subsequent events	In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in first quarter 2010. The adoption of this guidance did not have an impact on our financial statements.
Accounting Pronouncements Not Yet Adopted	In December 2010, the FASB issued ASU No. 2010-29, which updates the guidance in ASC Topic 805, Business Combinations. The objective of ASU 2010-29 is to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The amendments in ASU 2010-29 specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments affect any public entity as defined by ASC 805 that enters into business combinations that are material on an individual or aggregate basis. This guidance will become effective for us for acquisitions occurring on or after the beginning of our 2012 fiscal year. We do not expect the adoption of this guidance will have a material impact upon our financial position or results of operations.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2010

Summary of Significant Accounting Policies (Tables) [Abstract]

Accumulated Other Comprehensive Income (Loss)


	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive loss at December 31, 2007	$	(41,352	)	$	15,614		$	(25,738	)
Contract settlements reclassified to income		63,574			(24,158	)		39,416
Change in unrealized deferred hedging gains		98,008			(35,453	)		62,555
Adoption of fair value accounting for trading securities		2,022			(748	)		1,274


Accumulated other comprehensive income at December 31, 2008		122,252			(44,745	)		77,507
Contract settlements reclassified to income		(203,119	)		75,154			(127,965	)
Change in unrealized deferred hedging gains		91,059			(34,180	)		56,879


Accumulated other comprehensive income at December 31, 2009		10,192			(3,771	)		6,421
Contract settlements reclassified to income		(64,772	)		24,841			(39,931	)
Change in unrealized deferred hedging gains		165,642			(64,662	)		100,980


Accumulated other comprehensive income at December 31, 2010	$	111,062		$	(43,592	)	$	67,470

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2010

Income Taxes (Tables) [Abstract]

Reconciliation between the statutory federal income tax rate and effective income tax rate


	Year Ended December 31,
	2010			2009			2008
Federal statutory tax rate		(35.0	%)		(35.0	%)		35.0	%
State		(0.3	)		29.3			1.8
Valuation allowance		0.6			(2.8	)		(0.2	)
Other		0.1			0.2			(1.0	)

Consolidated effective tax (benefit) rate		(34.6	%)		(8.3	%)		35.6	%

Income tax benefit provision attributable to income from continuing operations


	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Current:
U.S. federal	$	—		$	(1,000	)	$	1,000
U.S. state and local		(836	)		364			3,268

	$	(836	)	$	(636	)	$	4,268


Deferred:
U.S. federal	$	(125,319	)	$	(20,913	)	$	186,436
U.S. state and local		(532	)		16,687			3,127

	$	(125,851	)	$	(4,226	)	$	189,563


Total tax (benefit) provision	$	(126,687	)	$	(4,862	)	$	193,831

Significant components of deferred tax assets and liabilities


	December 31,
	2010			2009
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	5,857		$	3,337
Current portion of asset retirement obligation		1,579			952
Other		4,106			6,207
Current portion of net operating loss carryforward		17,586			—

Total current		29,128			10,496


Non-current
Net operating loss carryforward		85,120			72,131
Deferred compensation		49,933			53,869
AMT credits and other credits		3,211			3,815
Non-current portion of asset retirement obligation		23,127			29,642
Cumulative unrealized mark-to-market loss		9,826			8,625
Other		23,481			20,311
Valuation allowance		(4,841	)		(2,555	)

Total non-current		189,857			185,838


Deferred tax liabilities:
Current
Net unrealized gain in AOCI		(40,976	)		(2,443	)

Total current		(40,976	)		(2,443	)


Non-current
Depreciation, depletion and investments		(858,502	)		(959,931	)
Net unrealized gain in AOCI		(2,616	)		(1,328	)
Other		(780	)		(1,543	)

Total non-current		(861,898	)		(962,802	)


Net deferred tax liability	$	(683,889	)	$	(768,911	)

(Loss) Income Per Common Share (Tables)

12 Months Ended

Dec. 31, 2010

Income (Loss) Per Common Share (Tables) [Abstract]

Computations of basic and diluted (loss) income per common share


	Year Ended December 31,
	2010			2009			2008
Numerator:
Net (loss) income	$	(239,256	)	$	(53,870	)	$	351,040
Less: Basic income allocable to participating securities ^(a)		(453	)		—			—

Basic net (loss) income attributable to common shareholders		(239,709	)		(53,870	)		351,040
Diluted adjustments to income allocable to participating securities ^(a)		—			—			—

Diluted net (loss) income attributable to common shareholders	$	(239,709	)	$	(53,870	)	$	351,040


Denominator:
Weighted average common shares outstanding — basic		156,874			154,514			151,116
Effect of dilutive securities:
Employee stock options, SARs and stock held in the deferred compensation plan		—			—			4,876
Treasury shares		—			—			(49	)

Weighted average common shares outstanding — diluted		156,874			154,514			155,943


(Loss) income per common share:
Basic — net (loss) income	$	(1.53	)	$	(0.35	)	$	2.32
Diluted — net (loss) income	$	(1.53	)	$	(0.35	)	$	2.25


^(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.

Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2010

Suspended Exploratory Well Costs (Tables) [Abstract]

Suspended Exploratory Well Costs


	2010			2009			2008
Balance at beginning of period	$	19,052		$	47,623		$	15,053
Additions to capitalized exploratory well costs pending the determination of proved reserves		28,897			26,216			43,968
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(24,041	)		(52,849	)		(3,847	)
Capitalized exploratory well costs charged to expense		—			(1,938	)		(7,551	)

Balance at end of period		23,908			19,052			47,623
Less exploratory well costs that have been capitalized for a period of one year or less		(13,181	)		(10,778	)		(41,681	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	10,727		$	8,274		$	5,942


Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		4			6			3

Aging of capitalized exploratory well costs that have been suspended for more than one year


	Total		2010		2009		2008
Capitalized exploratory well costs that have been capitalized for more than one year	$	10,727	$	4,546	$	4,602	$	1,579

Indebtedness (Tables)

12 Months Ended

Dec. 31, 2010

Indebtedness (Tables) [Abstract]

Debt Outstanding


	December 31,
	2010		2009
Bank debt (2.7%)	$	274,000	$	324,000

Senior subordinated notes:
7.375% senior subordinated notes due 2013, net of $1,638 discount in 2009		—		198,362
6.375% senior subordinated notes due 2015		150,000		150,000
7.5% senior subordinated notes due 2016, net of $317 and $363 discount, respectively		249,683		249,637
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 $13,147 and $14,166 discount, respectively		286,853		285,834
6.75% senior subordinated notes due 2020		500,000		—

Total debt	$	1,960,536	$	1,707,833

Schedule for the long-term debt outstanding


	Year Ended December 31,
2011	$	—
2012		274,000
2013		—
2014		—
2015		150,000
2016		249,682
Thereafter		1,286,854

	$	1,960,536

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2010

Asset Retirement Obligations (Tables) [Abstract]

Asset Retirement Obligations


	2010			2009
Beginning of period	$	78,812		$	83,457

Liabilities incurred		1,562			1,622
Acquisitions		556			—
Liabilities settled		(2,605	)		(724	)
Disposition of wells		(12,891	)		(15,946	)
Accretion expense		5,320			5,893
Change in estimate		(8,081	)		4,510

End of period		62,673			78,812


Less current portion		(4,020	)		(2,446	)


Long-term asset retirement obligations	$	58,653		$	76,366

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2010

Capital Stock (Tables) [Abstract]

Capital Stock


	Year Ended December 31,
	2010		2009		2008
Beginning balance		158,118,937		155,375,487		149,511,997
Public offerings		—		—		4,435,300
Shares issued in lieu of cash bonuses		—		184,926		—
Stock options/SARs exercised		991,988		1,384,861		1,339,536
Restricted stock grants		405,127		413,353		167,054
Issued for acreage purchases		380,229		743,737		—
Treasury shares		12,771		16,573		(78,400	)

Ending balance		159,909,052		158,118,937		155,375,487

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2010

Derivative Activities (Tables) [Abstract]

Derivative volumes hedged and average hedge prices


			Weighted
Period	Contract Type	Volume Hedged	Average Hedge Price
Natural Gas
2011	Collars	408,200 Mmbtu/day	$5.56– $6.48
2012	Collars	119,641 Mmbtu/day	$5.50– $6.25

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

Derivative Fair Value Income (Loss)


	2010			2009			2008
Change in fair value of derivatives that do not qualify for hedge accounting ^{(a) (c)}	$	(2,086	)	$	(115,909	)	$	85,594
Realized gain (loss) on settlement—natural gas ^(a) ^(b)		35,988			171,998			(1,383	)
Realized gain (loss) on settlement—oil ^{(a) (b)}		—			7,304			(15,431	)
Realized gain on early settlement of oil derivatives ^(c)		15,697			—			—
Hedge ineffectiveness—realized		(352	)		4,749			1,386
—unrealized ^(c)		2,387			(1,696	)		1,695

Derivative fair value income	$	51,634		$	66,446		$	71,861


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

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

^(c)		Not included in realized prices.

Combined fair value of derivatives, by Consolidated balance sheet


	December 31,
	2010			2009
Derivative assets:
Natural gas—collars	$	163,354		$	26,649
—basis swaps		—			(1,063	)
Crude oil—collars		—			66
—call options		(31,904	)		—

	$	131,450		$	25,652


Derivative liabilities:
Natural gas—collars	$	27,032		$	2,020
—basis swaps		(352	)		(16,779	)
Crude oil—collars		(12,051	)		—
—call options		(28,393	)		—

	$	(13,764	)	$	(14,759	)

Derivative Gross Assets and Gross Liabilities


	December 31, 2010								December 31, 2009
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying		Carrying			Net Carrying			Carrying		Carrying			Net Carrying
	Value		Value			Value			Value		Value			Value
Derivatives that qualify for cash flow hedge accounting :
Collars ^(a)	$	173,128	$	—		$	173,128		$	22,062	$	—		$	22,062

	$	173,128	$	—		$	173,128		$	22,062	$	—		$	22,062


Derivatives that do not qualify for hedge accounting :
Collars ^(a)	$	17,259	$	(12,052	)	$	5,207		$	6,673	$	—		$	6,673
Call options ^(a)		—		(60,297	)		(60,297	)		—		—			—
Basis swaps ^(a)		—		(352	)		(352	)		65		(17,907	)		(17,842	)

	$	17,259	$	(72,701	)	$	(55,442	)	$	6,738	$	(17,907	)	$	(11,169	)


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

Effects of cash flow hedges and other hedges on accumulated other comprehensive income (loss)


	Year Ended December 31,
							Realized Gain
	Change in Hedge						Reclassified from OCI
	Derivative Fair Value						into Revenue ^(a)
	2010			2009			2010			2009
Collars	$	165,642		$	91,059		$	64,772		$	203,119
Income taxes		(64,662	)		(34,180	)		(24,841	)		(75,154	)

	$	100,980		$	56,879		$	39,931		$	127,965


^(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.

Effects of non-hedge derivatives on consolidated statement of operations


	Year Ended December 31,
	Gain (Loss) Recognized in								Gain (Loss) Recognized in							Derivative Fair Value
	Income (Non-hedge Derivatives)								Income (Ineffective Portion)							Income
	2010			2009			2008		2010		2009		2008			2010			2009			2008
Swaps	$	—		$	63,755		$	14,395	$	—	$	—	$	(438	)	$	—		$	63,755		$	13,957
Collars		65,996			33,859			33,119		2,035		3,053		3,519			68,031			36,912			36,638
Call options		(15,895	)		—			—		—		—		—			(15,895	)		—			—
Basis swaps		(502	)		(34,221	)		21,266		—		—		—			(502	)		(34,221	)		21,266

Total	$	49,599		$	63,393		$	68,780	$	2,035	$	3,053	$	3,081		$	51,634		$	66,446		$	71,861

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2010

Fair Value Measurements (Tables) [Abstract]

Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value


	Fair Value Measurements at December 31, 2010 Using:
	Quoted Prices in		Significant
	Active Markets		Other			Significant		Total Carrying
	for Identical		Observable			Unobservable		Value as of
	Assets		Inputs			Inputs		December 31,
	(Level 1)		(Level 2)			(Level 3)		2010
Trading securities held in the deferred compensation plans	$	47,794	$	—		$	—	$	47,794

Derivatives—collars		—		178,335			—		178,335
—call options		—		(60,297	)		—		(60,297	)
—basis swaps		—		(352	)		—		(352	)


	Fair Value Measurements at December 31, 2009 Using:
	Quoted Prices in		Significant
	Active Markets		Other			Significant		Total Carrying
	for Identical		Observable			Unobservable		Value as of
	Assets		Inputs			Inputs		December 31,
	(Level 1)		(Level 2)			(Level 3)		2009
Trading securities held in the deferred compensation plans	$	43,554	$	—		$	—	$	43,554

Derivatives—collars		—		28,735			—		28,735
—basis swaps		—		(17,842	)		—		(17,842	)

Values of assets measured at fair value on nonrecurring basis


	Year Ended December 31,
	2010				2009
					Fair
	Fair Value		Impairment		Value		Impairment
Natural gas and oil properties	$	851,988	$	469,749	$	1,244	$	930
Equity investments	$	—	$	—	$	2,895	$	8,950

Carrying Amounts and Fair Values of Financial Instruments


	December 31, 2010						December 31, 2009
	Carrying			Fair			Carrying			Fair
	Value			Value			Value			Value
Assets:
Commodity swaps, collars and call options	$	131,450		$	131,450		$	25,652		$	25,652
Marketable securities ^(a)		47,794			47,794			43,554			43,554

Liabilities:
Commodity swaps, collars and call options		(13,764	)		(13,764	)		(14,759	)		(14,759	)
Long-term debt ^(b)		(1,960,536	)		(2,055,813	)		(1,707,833	)		(1,842,625	)


^(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.

Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2010

Stock based compensation plans (Tables) [Abstract]

Stock Option And SARs Activities


				Weighted
				Average
	Shares			Exercise Price
Outstanding at December 31, 2007		7,772,325		$	17.95
Granted		1,159,649			63.18
Exercised		(1,590,390	)		12.24
Expired/forfeited		(92,918	)		40.82

Outstanding at December 31, 2008		7,248,666			26.15
Granted		1,714,165			36.90
Exercised		(1,717,584	)		14.31
Expired/forfeited		(90,535	)		40.73

Outstanding at December 31, 2009		7,154,712			31.38
Granted		1,394,136			46.09
Exercised		(1,883,091	)		20.49
Expired/forfeited		(203,918	)		48.18

Outstanding at December 31, 2010		6,461,839		$	37.20

Outstanding stock options and SARs


	Outstanding						Exercisable
			Weighted-
			Average		Weighted-				Weighted
			Remaining		Average				Average
			Contractual		Exercise				Exercise
Range of Exercise Prices	Shares		Life		Price		Shares		Price
$ 1.29– $9.99		770,056		1.10	$	3.55		770,056	$	3.55
10.00–19.99		15,435		4.73		19.63		15,435		19.63
20.00–29.99		780,219		0.26		24.32		780,219		24.32
30.00–39.99		1,958,221		1.94		34.49		1,373,383		34.60
40.00–49.99		1,938,906		3.90		44.69		293,309		42.36
50.00–59.99		634,837		1.94		58.32		404,805		58.53
60.00–69.99		18,927		2.42		65.56		11,356		65.56
70.00–75.00		345,238		2.29		75.00		224,285		75.00

Total		6,461,839		2.25	$	37.20		3,872,848	$	31.82

Weighted average grant date fair value of Sars


	2010			2009			2008
Weighted average exercise price per share	$	46.09		$	36.90		$	63.18
Expected annual dividends per share		0.35	%		0.44	%		0.26	%
Expected life in years		3.6			3.5			3.5
Expected volatility		49	%		58	%		41	%
Risk-free interest rate		1.6	%		1.5	%		2.4	%
Weighted average grant date fair value of SARs granted	$	17.01		$	15.42		$	20.58

Non-vested restricted stock outstanding


				Weighted
				Average Grant
	Shares			Date Fair Value
Non-vested shares outstanding at December 31, 2007		563,660		$	30.42
Granted		362,313			63.00
Vested		(438,058	)		37.54
Forfeited		(14,368	)		38.87


Non-vested shares outstanding at December 31, 2008		473,547			48.50
Granted		685,578			39.99
Vested		(521,536	)		40.91
Forfeited		(10,400	)		40.83


Non-vested shares outstanding at December 31, 2009		627,189			45.64
Granted		413,422			45.83
Vested		(439,361	)		46.90
Forfeited		(18,499	)		46.04

Non-vested shares outstanding at December 31, 2010		582,751		$	44.81

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2010

Supplemental Cash Flow Information (Tables) [Abstract]

Supplemental Cash Flow Information


	Year Ended December 31,
	2010			2009		2008
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(1,359	)	$	170	$	4,298
Interest paid		116,766			108,685		93,954

Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net		(6,523	)		6,131		4,647
Unproved property purchased with stock		20,000			33,726		—
Shares issued in lieu of bonuses		—			6,312		—

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2010

Commitments and Contingencies (Tables) [Abstract]

Future minimum rental commitments


	Operating
	Lease
	Obligations
2011	$	9,913
2012		10,054
2013		7,067
2014		6,395
2015		6,368
Thereafter		27,833
Sublease rentals		(615	)

	$	67,015

Transportation commitments


	Transportation
	Commitments
2011	$	68,587
2012		65,824
2013		64,794
2014		61,351
2015		59,870
Thereafter		381,697

	$	702,123

Office Closing and Exit Activities (Tables)

12 Months Ended

Dec. 31, 2010

Office Closing and Exit Activities (Tables) [Abstract]

Exit activities included in accrued liabilities in consolidated balance sheet


	2010			2009
Beginning balance	$	1,568		$	—
Accrued one-time termination costs		5,138			1,895
Office lease		514			252
Payments		(6,128	)		(579	)

Ending balance	$	1,092		$	1,568

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2010

Selected Quarterly Financial Data (Tables) [Abstract]

Selected Quarterly Financial Data


	2010
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGL and oil sales	$	236,760		$	206,784		$	219,560		$	246,503		$	909,607
Transportation and gathering		2,093			674			(1,634	)		(65	)		1,068
Derivative fair value income (loss)		42,333			6,546			9,981			(7,226	)		51,634
Gain on the sale of assets		68,868			10,176			67			(1,514	)		77,597
Other		(1,575	)		637			(1,013	)		1,020			(931	)

Total revenue and other income		348,479			224,817			226,961			238,718			1,038,975


Costs and expenses:
Direct operating		31,040			29,775			34,287			36,500			131,602
Production and ad valorem taxes		8,070			8,090			8,873			8,619			33,652
Exploration		14,635			14,473			15,236			16,743			61,087
Abandonment and impairment of unproved properties		12,407			13,497			20,534			23,533			69,971
General and administrative		28,170			35,836			36,523			40,042			140,571
Termination costs		7,938			—			—			514			8,452
Deferred compensation plan		(5,712	)		(14,135	)		(5,347	)		14,978			(10,216	)
Interest expense		30,287			30,779			33,806			36,320			131,192
Loss on early extinguishment of debt		—			—			5,351			—			5,351
Depletion, depreciation and amortization		88,626			90,997			91,768			92,116			363,507
Impairment of proved properties		6,505			—			—			463,244			469,749

Total costs and expenses		221,966			209,312			241,031			732,609			1,404,918


Income (loss) before income taxes		126,513			15,505			(14,070	)		(493,891	)		(365,943	)

Income tax expense (benefit)
Current		—			—			(10	)		(826	)		(836	)
Deferred		48,934			6,453			(5,892	)		(175,346	)		(125,851	)

		48,934			6,453			(5,902	)		(176,172	)		(126,687	)


Net income (loss)	$	77,579		$	9,052		$	(8,168	)	$	(317,719	)	$	(239,256	)


Income (loss) per common share:
Basic	$	0.50		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.53	)


Diluted	$	0.48		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.53	)


	2009
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGL and oil sales	$	203,189		$	192,523		$	202,122		$	242,087		$	839,921
Transportation and gathering		(505	)		2,152			2,444			(3,605	)		486
Derivative fair value income (loss)		75,547			(9,856	)		(482	)		1,237			66,446
Gain on the sale of assets		36			(29	)		32			10,374			10,413
Other		(1,830	)		(4,358	)		(475	)		(3,262	)		(9,925	)

Total revenue and other income		276,437			180,432			203,641			246,831			907,341


Costs and expenses:
Direct operating		35,541			34,828			31,111			31,731			133,211
Production and ad valorem taxes		8,257			7,564			7,600			8,748			32,169
Exploration		13,339			11,368			10,902			10,876			46,485
Abandonment and impairment of unproved properties		19,572			40,954			24,053			28,959			113,538
General and administrative		24,910			29,103			29,928			31,378			115,319
Termination costs		—			—			840			1,639			2,479
Deferred compensation plan		12,434			756			16,445			1,438			31,073
Interest expense		26,629			29,555			30,633			30,550			117,367
Depletion, depreciation and amortization		84,320			88,713			97,208			103,261			373,502
Impairment of proved properties		—			—			—			930			930

Total costs and expenses		225,002			242,841			248,720			249,510			966,073


Income (loss) before income taxes		51,435			(62,409	)		(45,079	)		(2,679	)		(58,732	)

Income tax expense (benefit)
Current		—			619			(695	)		(560	)		(636	)
Deferred		18,827			(23,145	)		(14,566	)		14,658			(4,226	)

		18,827			(22,526	)		(15,261	)		14,098			(4,862	)


Net income (loss)	$	32,608		$	(39,883	)	$	(29,818	)	$	(16,777	)	$	(53,870	)


Income (loss) per common share:
Basic	$	0.21		$	(0.26	)	$	(0.19	)	$	(0.11	)	$	(0.35	)


Diluted	$	0.21		$	(0.26	)	$	(0.19	)	$	(0.11	)	$	(0.35	)

Principal Unconsolidated Investees (unaudited)


Company	December 31, 2010 Ownership			Activity
Whipstock Natural Gas Services, LLC		50	%	Drilling services
Nora Gathering, LLC		50	%	Gas gathering and transportation

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Tables)

12 Months Ended

Dec. 31, 2010

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Tables) [Abstract]

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization


	December 31,
	2010			2009			2008
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	5,749,620		$	5,534,204		$	5,271,020
Unproved properties		811,834			774,503			757,960

Total		6,561,454			6,308,707			6,028,980
Accumulated depreciation, depletion and amortization		(1,639,397	)		(1,409,888	)		(1,186,934	)

Net capitalized costs	$	4,922,057		$	4,898,819		$	4,842,046


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

Costs Incurred for Property Acquisition, Exploration and Development


	Year Ended December 31,
	2010			2009		2008
	(in thousands)
Acquisitions:
Unproved leasehold	$	3,697		$	—	$	99,446
Proved oil and gas properties		130,767			—		251,471
Asset retirement obligations		556			—		251
Acreage purchases ^(b)		166,677			176,867		494,341
Development		784,153			497,702		729,268
Exploration:
Drilling		50,737			57,121		133,116
Expense		56,879			42,082		63,560
Stock-based compensation expense		4,209			4,817		4,130
Gas gathering facilities:
Development		20,726			29,524		47,056

Subtotal		1,218,401			808,113		1,822,639

Asset retirement obligations		(6,523	)		6,131		4,647


Total costs incurred	$	1,211,878		$	814,244	$	1,827,286


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

^(b)		2009 includes $20.0 million accrued for acreage purchases for which 380,229 shares were issued in January 2010. 2008 includes a single transaction to acquire Marcellus Shale acreage for $223.9 million.

Proved developed and undeveloped reserves


										Natural Gas
	Natural Gas			NGLs			Crude Oil			Equivalents ^(a)
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe)
Proved developed and undeveloped reserves:
Balance, December 31, 2007		1,832,797			17,748			48,912			2,232,762
Revisions		(23,397	)		1,791			(4,946	)		(42,333	)
Extensions, discoveries and additions		423,354			5,643			10,198			518,404
Purchases		95,262			53			—			95,578
Property sales		(147	)		—			(1,592	)		(9,701	)
Production		(114,323	)		(1,386	)		(3,085	)		(141,145	)


Balance, December 31, 2008		2,213,546			23,849			49,487			2,653,565
Revisions		(37,497	)		8,434			(1,536	)		3,890
Extensions, discoveries and additions		620,114			21,492			3,479			769,939
Purchases		—			—			—			—
Property sales		(50,797	)		—			(14,791	)		(139,543	)
Production		(130,649	)		(2,187	)		(2,557	)		(159,112	)


Balance, December 31, 2009		2,614,717			51,588			34,082			3,128,739
Revisions		3,599			26,832			(2,672	)		148,558
Extensions, discoveries and additions		1,089,632			48,792			4,663			1,410,359
Purchases		124,981			—			—			124,981
Property sales		(124,369	)		—			(10,865	)		(189,558	)
Production		(142,034	)		(4,490	)		(1,969	)		(180,789	)


Balance, December 31, 2010		3,566,526			122,722			23,239			4,442,290


Proved developed reserves:
December 31, 2008		1,337,978			16,398			32,611			1,632,032

December 31, 2009		1,445,705			26,205			20,626			1,726,696

December 31, 2010		1,762,766			53,071			17,050			2,183,488


Proved undeveloped reserves:
December 31, 2008		875,567			7,451			16,876			1,021,531

December 31, 2009		1,169,012			25,382			13,457			1,402,043

December 31, 2010		1,803,760			69,651			6,189			2,258,802


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

Changes in proved undeveloped reserves for 2010 (Mmcfe)


Beginning proved undeveloped reserves-2009	1,402,043
Undeveloped reserves transferred to developed	(191,220	)
Revisions	(75,685	)
Purchases/sales	(25,643	)
Extension and discoveries	1,149,307

Ending proved undeveloped reserves-2010	2,258,802

Standardized measure of Discounted future net cash flows


	As of December 31,
	2010			2009
	(in thousands)
Future cash inflows	$	19,676,630		$	11,969,906
Future costs:
Production		(4,305,292	)		(3,371,762	)
Development		(2,855,407	)		(1,877,330	)


Future net cash flows before income taxes		12,515,931			6,720,814

Future income tax expense		(3,923,264	)		(1,767,965	)


Total future net cash flows before 10% discount		8,592,667			4,952,849

10% annual discount		(5,113,541	)		(2,861,760	)


Standardized measure of discounted future net cash flows	$	3,479,126		$	2,091,089

Changes in Discounted future net cash flows


	As of December 31,
	2010			2009			2008
	(in thousands)
Beginning of period	$	2,091,089		$	2,581,380		$	3,666,363
Revisions of previous estimates:
Changes in prices		957,994			(992,809	)		(1,675,703	)
Revisions in quantities		190,874			4,124			(65,931	)
Changes in future development costs		(474,058	)		(375,344	)		(688,259	)
Accretion of discount		259,280			340,025			520,482
Net change in income taxes		(666,517	)		317,158			719,595
Purchases of reserves in place		160,580			—			148,857
Additions to proved reserves from extensions, discoveries and improved recovery		1,812,077			816,278			807,386
Production		(744,354	)		(673,907	)		(1,029,001	)
Development costs incurred during the period		298,624			316,523			333,979
Sales of natural gas and oil		(243,551	)		(147,942	)		(15,109	)
Timing and other		(162,912	)		(94,397	)		(141,279	)

End of period	$	3,479,126		$	2,091,089		$	2,581,380

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Accumulated Other Comprehensive Income Loss
Beginning Balance, gross	$ 10,192	$ 122,252	$ (41,352)
Beginning balance, Net of tax	6,421	77,507	(25,738)
Beginning balance, Tax Effect	(3,771)	(44,745)	15,614
Contract settlements reclassified to income, before tax	(64,772)	(203,119)	63,574
Contract settlements reclassified to income, Tax effect	24,841	75,154	(24,158)
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss), net of taxes	(39,931)	(127,965)	39,416
Change in unrealized deferred hedging gains, before tax	165,642	91,059	98,008
Change in unrealized deferred hedging gains, Tax Effect	(64,662)	(34,180)	(35,453)
Change in unrealized deferred hedging gains, Net of Tax	100,980	56,879	62,555
Adoption of fair value accounting for trading securities, Net of Tax			0
Ending Balance, gross	111,062	10,192	122,252
Ending Balance, Tax Effect	(43,592)	(3,771)	(44,745)
Ending Balance, Net of Tax	$ 67,470	$ 6,421	77,507
Accumulated other comprehensive (loss) income
Accumulated Other Comprehensive Income Loss
Adoption of fair value accounting for trading securities, Gross			2,022
Adoption of fair value accounting for trading securities, Tax Effect			(748)
Adoption of fair value accounting for trading securities, Net of Tax			$ 1,274

Summary of Significant Accounting Policies (Details Textuals)	3 Months Ended								12 Months Ended
	Dec. 31, 2010 USD ($)	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Sep. 30, 2009 USD ($)	Jun. 30, 2009 USD ($)	Mar. 31, 2009 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Summary of Significant Accounting Policies (Textuals) [Abstract]
Allowance for doubtful accounts on accounts receivables	$ 5,001,000				$ 2,176,000				$ 5,001,000	$ 2,176,000
Allowance for bad debts									3,608,000	1,351,000	$ 450,000
Liabliity due to insufficient reserves	587,000								$ 587,000
Maturity period of cash and cash equivalents									3 months or less
Mcf of gas equating to one barrel of oil									6
Increase in depletion, depreciation and amortization expense, before tax										3,400,000
Increase in depletion, depreciation and amortization expense after tax										2,200,000
Net book value of unproved properties	811,800,000				774,500,000				$ 811,800,000	774,500,000
Abandonment and impairment of unproved properties	23,533,000	$ 20,534,000	$ 13,497,000	$ 12,407,000	28,959,000	$ 24,053,000	$ 40,954,000	$ 19,572,000	69,971,000	113,538,000	47,355,000
Depreciation expense									16,200,000	31,700,000	13,700,000
Accelerated depreciation expense					10,300,000
Unamortized debt issuance costs	27,900,000								27,900,000
Marketable securities	47,800,000								47,800,000
Other investments	9,300,000								9,300,000
Gain loss as a result of the discontinuance of hedge accounting treatment for derivatives									11,600,000	5,400,000	$ 583,000
Bank Over draft balance included in Accounts Payable	$ 97,200,000				$ 33,100,000				$ 97,200,000	$ 33,100,000
Building [Member]
Property, Plant and Equipment [Line Items]
Minimum estimated useful lives									10
Maximum estimated useful lives									15
Gas transportation and gathering systems [Member]
Property, Plant and Equipment [Line Items]
Minimum estimated useful lives									10
Maximum estimated useful lives									15
Associated assets [Member]
Property, Plant and Equipment [Line Items]
Minimum estimated useful lives									5
Maximum estimated useful lives									7

Dispositions and Acquisitions (Details)	1 Months Ended			3 Months Ended				12 Months Ended
Dispositions and Acquisitions (Details)	Feb. 28, 2011 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010	Sep. 30, 2010 USD ($)	Dec. 31, 2009 USD ($)	Jun. 30, 2009 USD ($)	Mar. 31, 2008 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Significant Acquisitions and Disposals [Line Items]
Acquisitions of unproved property		$ 3,700,000						$ 3,697,000		$ 99,446,000
Proceeds from sale of oil and gas properties					$ 36,300,000	$ 181,800,000		327,765,000	$ 234,076,000	68,231,000
Purchase price allocated to proved properties								130,767,000		251,471,000
Dispositions and Acquisitions (Textuals) [Abstract]
Percentage of sale closed			90.00%
Proceeds used to repay outstanding borrowings under credit facility				$ 135,000,000				1,105,000,000	1,076,000,000	1,086,500,000
Ohio Properties [Member]
Significant Acquisitions and Disposals [Line Items]
Gain from sale of oil and gas properties								77,600,000
Proceeds from sale of oil and gas properties								323,000,000
Marcellus Shale Acreage [Member]
Significant Acquisitions and Disposals [Line Items]
Gain on sale of Marcellus Shale Acreage									10,400,000
Proceeds on sale of Marcellus Shale Acreage									$ 11,200,000
Barnett Shale Properties [Member]
Significant Acquisitions and Disposals [Line Items]
Acquisitions of unproved property								$ 99,400,000
Proceeds from sale of oil and gas properties	$ 900,000,000
Number of Productive Wells								360
Acquisitions of producing and unproved properties										$ 331,200,000
Purchase price allocated to proved properties								$ 232,900,000
Asset retirement obligations and transactions costs								$ 827,000
Number of drilling locations								700
East Texas Properties [Member]
Significant Acquisitions and Disposals [Line Items]
Gain from sale of oil and gas properties							$ 20,200,000
Proceeds from sale of oil and gas properties							$ 64,000,000
Virginia Properties [Member]
Significant Acquisitions and Disposals [Line Items]
Acquisitions of producing and unproved properties		134,500,000
Purchase price allocated to proved properties		$ 131,300,000

Income Taxes (Details)	12 Months Ended
Income Taxes (Details)	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Reconciliation between the statutory federal income tax rate and effective income tax rate benefit
Federal statutory tax rate	(35.00%)	(35.00%)	35.00%
State	(0.30%)	29.30%	1.80%
Valuation allowance	0.60%	(2.80%)	(0.20%)
Other	0.10%	0.20%	(1.00%)
Consolidated effective tax (benefit) rate	(34.60%)	(8.30%)	35.60%

Income Taxes (Details 1) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Income Taxes (Details 1) - USD ($) $ in Thousands	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current:
U.S. federal									$ 0	$ (1,000)	$ 1,000
U.S. state and local									(836)	364	3,268
Current	$ (826)	$ (10)			$ (560)	$ (695)	$ 619		(836)	(636)	4,268
Deferred:
U.S. federal									(125,319)	(20,913)	186,436
U.S. state and local									(532)	16,687	3,127
Deferred	(175,346)	(5,892)	$ 6,453	$ 48,934	14,658	(14,566)	(23,145)	$ 18,827	(125,851)	(4,226)	189,563
Total tax (benefit) provision	$ (176,172)	$ (5,902)	$ 6,453	$ 48,934	$ 14,098	$ (15,261)	$ (22,526)	$ 18,827	$ (126,687)	$ (4,862)	$ 193,831

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Current
Deferred compensation	$ 5,857	$ 3,337
Current portion of asset retirement obligation	1,579	952
Other	4,106	6,207
Current portion of net operating loss carryforward	17,586	0
Total current	29,128	10,496
Non-current
Net operating loss carryforward	85,120	72,131
Deferred compensation	49,933	53,869
AMT credits and other credits	3,211	3,815
Non-current portion of asset retirement obligation	23,127	29,642
Cumulative unrealized mark-to-market loss	9,826	8,625
Other	23,481	20,311
Valuation allowance	(4,841)	(2,555)
Total non-current	189,857	185,838
Current
Net unrealized gain in AOCI	(40,976)	(2,443)
Total current	(40,976)	(2,443)
Non Current
Depreciation depletion and investments	(858,502)	(959,931)
Net unrealized gain in AOCI	(2,616)	(1,328)
Other	(780)	(1,543)
Total non-current	(861,898)	(962,802)
Net deferred tax liability	$ (683,889)	$ (768,911)

Income Taxes (Details Textuals) - USD ($)	3 Months Ended								12 Months Ended
Income Taxes (Details Textuals) - USD ($)	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Income Taxes (Textuals) [Abstract]
Total income tax expense	$ (176,172,000)	$ (5,902,000)	$ 6,453,000	$ 48,934,000	$ 14,098,000	$ (15,261,000)	$ (22,526,000)	$ 18,827,000	$ (126,687,000)	$ (4,862,000)	$ 193,831,000
Deferred tax liability related to net deferred hedging gains included in OCI	43,600,000								43,600,000
Deferred tax liabilities exceed deferred tax assets	(683,889,000)				(768,911,000)				(683,889,000)	(768,911,000)
Valuation allowance recorded against capital loss carryover					600,000					600,000
Valuation allowance on deferred compensation plan	4,800,000				$ 2,000,000				4,800,000	$ 2,000,000
Deductible limit	1,000,000								1,000,000
Regular net operating loss carryforwards	413,200,000								413,200,000
Alternative minimum tax carryforwards	363,900,000								363,900,000
Defered tax asset related to NOL carryforward net of stock compensation reduction for unrealized benefits	102,700,000								102,700,000
Alternative Minimum tax credit carry forwards that are not subject to limitation or expiration	665,000								665,000
Accrued interest or penalties related to tax amounts	$ 0								$ 0

(Loss) Income Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Numerator:
Net (loss) income	$ (317,719)	$ (8,168)	$ 9,052	$ 77,579	$ (16,777)	$ (29,818)	$ (39,883)	$ 32,608	$ (239,256)	$ (53,870)	$ 351,040
Less: Basic income allocable to participating securities									(453)
Basic net (loss) income attributable to common shareholders									(239,709)	(53,870)	351,040
Diluted adjustments to income allocable to participating securities									0
Diluted net (loss) income attributable to common shareholders									$ (239,709)	$ (53,870)	$ 351,040
Denominator:
Weighted average common shares outstanding - basic									156,874,000	154,514,000	151,116,000
Effect of dilutive securities:
Employee stock options, SARs and stock held in the deferred compensation plan											4,876,000
Treasury Shares											(49,000)
Weighted average common shares outstanding-diluted									156,874,000	154,514,000	155,943,000
(Loss) income per common share:
Basic-net (loss) income	$ (2.02)	$ (0.05)	$ 0.06	$ 0.50	$ (0.11)	$ (0.19)	$ (0.26)	$ 0.21	$ (1.53)	$ (0.35)	$ 2.32
Diluted- net (loss) income	$ (2.02)	$ (0.05)	$ 0.06	$ 0.48	$ (0.11)	$ (0.19)	$ (0.26)	$ 0.21	$ (1.53)	$ (0.35)	$ 2.25
Income (Loss) Per Common Share (Textuals)
Weighted Average Common Shares, Restricted Stock									2,800,000	2,600,000	2,300,000
Stock appreciation rights excluded from earning per share calculation											880,000

Suspended Exploratory Well Costs (Details) $ in Thousands	12 Months Ended
Suspended Exploratory Well Costs (Details) $ in Thousands	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Suspended Exploratory Well Costs
Beginning balance at January 1	$ 19,052	$ 47,623	$ 15,053
Additions to capitalized exploratory well costs pending the determination of proved reserves	28,897	26,216	43,968
Reclassifications to wells, facilities and equipment based on determination of proved reserves	(24,041)	(52,849)	(3,847)
Capitalized exploratory well costs charged to expense	0	(1,938)	(7,551)
Balance at end of period	23,908	19,052	47,623
Less exploratory well costs that have been capitalized for a period of one year or less	(13,181)	(10,778)	(41,681)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 10,727	$ 8,274	$ 5,942
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	4	6	3
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 10,727	$ 8,274	$ 5,942
Exploratory Well Costs Capitalized in Year 2010 [Member]
Suspended Exploratory Well Costs
Capitalized exploratory well costs that have been capitalized for a period greater than one year	4,546
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 4,546
Exploratory Well Costs Capitalized in Year 2009 [Member]
Suspended Exploratory Well Costs
Capitalized exploratory well costs that have been capitalized for a period greater than one year		4,602
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$ 4,602
Exploratory Well Costs Capitalized in Year 2008 [Member]
Suspended Exploratory Well Costs
Capitalized exploratory well costs that have been capitalized for a period greater than one year			1,579
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for a period greater than one year			$ 1,579

Suspended Exploratory Well Costs (Details Textuals) $ in Thousands	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Suspended Exploratory Well Costs (Textuals) [Abstract]
Marcellus Shale Wells waiting on pipelines	3
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 10,727	$ 8,274	$ 5,942

Indebtedness (Details) - USD ($) $ in Thousands	Feb. 25, 2011	Dec. 31, 2010	Dec. 31, 2009
Indebtedness
Bank debt	$ 440,000	$ 274,000	$ 324,000
Senior subordinated notes:
Subordinated debt		1,686,536	1,383,833
Total debt		1,960,536	1,707,833
7.375% senior subordinated notes due 2013, net of discount [Member]
Senior subordinated notes:
Subordinated debt		0	198,362
6.375% Senior Subordinated Notes due 2015 [Member]
Senior subordinated notes:
Subordinated debt		150,000	150,000
7.5% Senior Subordinated Notes due 2017 [Member]
Senior subordinated notes:
Subordinated debt		250,000	250,000
7.5% senior subordinated notes due 2016, net of discount [Member]
Senior subordinated notes:
Subordinated debt		249,683	249,637
7.25% Senior Subordinated Notes due 2018 [Member]
Senior subordinated notes:
Subordinated debt		250,000	250,000
8.0% senior subordinated notes due 2019, net of discount [Member]
Senior subordinated notes:
Subordinated debt		286,853	285,834
6.75% Senior Subordinated Notes due 2020 [Member]
Senior subordinated notes:
Subordinated debt		$ 500,000	$ 0

Indebtedness (Details 1) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Schedule for the long-term debt outstanding
2011	$ 0
2012	274,000
2013	0
2014	0
2015	150,000
2016	249,682
Thereafter	1,286,854
Total debt	$ 1,960,536	$ 1,707,833

Indebtedness (Details Textuals) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
Indebtedness (Details Textuals) $ in Thousands	Aug. 31, 2010 USD ($)	Sep. 30, 2010 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Aug. 01, 2018	Aug. 01, 2015	Aug. 01, 2013	Feb. 25, 2011 USD ($)	Feb. 18, 2011 USD ($)
Debt Instrument [Line Items]
Maximum redemption price of 6.75% notes as a percentage of principal amount								106.75%
Net proceeds after underwriting discounts and commissions			$ 500,000	$ 285,201	$ 250,000
Proceeds used to repay outstanding borrowings under credit facility		$ 135,000	1,105,000	1,076,000	1,086,500
Repayments of subordinated debt			202,458
Indebtedness (Textuals) [Abstract]
Interest Costs, Capitalized During Period			0	0	$ 0
Bank Credit facility, Borrowing base			1,500,000							$ 2,000,000
Bank Credit facility, Facility amount			$ 1,250,000							$ 1,500,000
Number of commercial banks included in current bank group			26							27
Percentage holding of commercial banks, Maximum			5.00%							7.00%
Notice period for increase in facility amount, in days			20							20
Outstanding balance under the bank credit facility			$ 274,000	$ 324,000					$ 440,000
Undrawn letters of credit			$ 5,400
Maturity date of loan			Oct. 25, 2012						Feb. 18, 2016
Borrowing capacity available under the facility amount			$ 970,100						$ 1,100,000	$ 1,000,000
Spread for Alternate Base Rate, Minimum			0.875%						0.50%
Spread for Alternate Base Rate, Maximum			1.625%						1.50%
Spread for LIBO Rate, Minimum			1.75%						1.50%
Spread for LIBO Rate, Maximum			2.50%						2.50%
Weighted average interest rate on the bank credit facility			2.20%	2.40%	4.40%
Annual rate of commitment fee paid on the undrawn balance, Minimum			0.375%						0.375%
Annual rate of commitment fee paid on the undrawn balance, Maximum			0.50%						0.50%
Commitment Fee Rate			0.375%						0.375%
Interest rate margin on LIBOR loans			1.75%						1.50%
Interest rate margin on base rate loans			0.875%						0.50%
Maximum percentage of the original aggregate amount of the 6.75% notes that can be redeemed								35.00%
Minimum percentage of the original aggregate principal amount of the 6.75% notes to remain outstanding immediately after the redemption								65.00%
Maximum number of days after the date of the closing of the equity offering that the redemption should occur								60
Loss on early extinguishment of debt		$ 5,351	$ 5,351
Purchase price of all senior subordinate notes as a percentage of principal amount			101.00%
Ratio of debt to EBITDAX			4
Current ratio			1
Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Aggregate principal amount of 6.75% senior subordinated notes due 2020	$ 500,000
Maximum redemption price of 6.75% notes as a percentage of principal amount						100.00%	103.375%
Net proceeds after underwriting discounts and commissions	$ 491,300
Proceeds used to repay outstanding borrowings under credit facility			$ 287,100
Repayments of subordinated debt			$ 204,200
7.375% senior subordinated notes due 2013, net of discount [Member]
Debt Instrument [Line Items]
Discount on senior subordinated notes				$ 1,638
Interest Rate on Senior Subordinated Notes			7.375%
Redemption price of 7.375% notes as a percentage of principal amount	101.229%
7.5% senior subordinated notes due 2016, net of discount [Member]
Debt Instrument [Line Items]
Discount on senior subordinated notes			$ 317	363
8.0% senior subordinated notes due 2019, net of discount [Member]
Debt Instrument [Line Items]
Discount on senior subordinated notes			$ 13,147	$ 14,166
6.75% Senior Subordinated Notes due 2020 [Member]
Debt Instrument [Line Items]
Interest Rate on Senior Subordinated Notes			6.75%

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligations
Beginning of period	$ 78,812	$ 83,457
Liabilities incurred	1,562	1,622
Acquisitions	556
Liabilities settled	(2,605)	(724)
Disposition of wells	(12,891)	(15,946)
Accretion expense	5,320	5,893
Change in estimate	(8,081)	4,510
End of period	62,673	78,812
Less current portion	(4,020)	(2,446)
Long Term Asset Retirement Obligation	$ 58,653	$ 76,366

Capital Stock (Details) - shares	12 Months Ended
Capital Stock (Details) - shares	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Capital Stock
Beginning balance	158,118,937	155,375,487	149,511,997
Public offerings			4,435,300
Shares issued in lieu of cash bonuses		184,926
Stock options/SARs exercised	991,988	1,384,861	1,339,536
Restricted stock grants	405,127	413,353	167,054
Issued for acreage purchases	380,229	743,737
Treasury shares	12,771	16,573	(78,400)
Ending balance	159,909,052	158,118,937	155,375,487

Capital Stock (Details Textuals)	3 Months Ended			6 Months Ended			9 Months Ended			12 Months Ended
Capital Stock (Details Textuals)	Mar. 31, 2010 $ / shares	Mar. 31, 2009 $ / shares	Mar. 31, 2008 $ / shares	Jun. 30, 2010 $ / shares	Jun. 30, 2009 USD ($) $ / shares	Jun. 30, 2008 $ / shares	Sep. 30, 2010 $ / shares	Sep. 30, 2009 $ / shares	Sep. 30, 2008 $ / shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) shares	Dec. 31, 2009 $ / shares shares	Dec. 31, 2009 USD ($) shares	Dec. 31, 2008 USD ($) $ / shares shares
Capital Stock (Textuals) [Abstract]
Authorized capital stock \| shares										485,000,000	485,000,000
Common stock, shares authorized \| shares										475,000,000	475,000,000	475,000,000	475,000,000
Preferred stock, shares authorized \| shares										10,000,000	10,000,000	10,000,000	10,000,000
Repurchase of common stock, value														$ 3,200,000
Repurchase of common stock, approved total														10,000,000
Average purchase price per common stock														$ 41.11
Repurchase of common stock, shares \| shares										12,771	12,771	16,573	16,573	(78,400)
Remaining common stock, under authorization										$ 6,800,000	$ 6,800,000
Registration statement issued to sell shares					$ 200,000,000
Remaining amount in the Registration statement										$ 156,400,000	156,400,000
Common Stock dividends declared per share \| (per share)	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.16	$ 0.04	$ 0.16	$ 0.04

Derivative Activities (Details)	Dec. 31, 2010 USD ($)
Derivative volumes hedged and average hedge prices
Weighted average prices of call option of oil (per barrel)	82.31
Crude Oil 2011 [Member] \| Call Option [Member]
Derivative volumes hedged and average hedge prices
Volume Hedged	5,500 bbls/day
Weighted average prices of call option of oil (per barrel)	80.00
Crude Oil 2012 [Member] \| Collars [Member]
Derivative volumes hedged and average hedge prices
Volume Hedged	2,000 bbls/day
Weighted average floor prices	70.00
Weighted average cap prices	80.00
Crude Oil 2012 [Member] \| Call Option [Member]
Derivative volumes hedged and average hedge prices
Volume Hedged	4,700 bbls/day
Weighted average prices of call option of oil (per barrel)	85.00
Natural Gas [Member]
Derivative volumes hedged and average hedge prices
Weighted average floor prices	5.54
Weighted average cap prices	6.43
Natural Gas 2011 [Member] \| Collars [Member]
Derivative volumes hedged and average hedge prices
Volume Hedged	408,200 Mmbtu/day
Weighted average floor prices	5.56
Weighted average cap prices	6.48
Natural Gas 2012 [Member] \| Collars [Member]
Derivative volumes hedged and average hedge prices
Volume Hedged	119,641 Mmbtu/day
Weighted average floor prices	5.50
Weighted average cap prices	6.25

Derivative Activities (Details 1) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Derivative Activities (Details 1) - USD ($) $ in Thousands	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Derivative Fair Value Income (Loss)
Change in fair value of derivatives that do not qualify for hedge accounting									$ (2,086)	$ (115,909)	$ 85,594
Realized gain (loss) on settlement - natural gas									35,988	171,998	(1,383)
Realized gain (loss) on settlement - oil										7,304	(15,431)
Realized gain on early settlement of oil derivatives									15,697
Hedge ineffectiveness - realized									(352)	4,749	1,386
Hedge ineffectiveness - unrealized									2,387	(1,696)	1,695
Derivative Fair Value Income	$ (7,226)	$ 9,981	$ 6,546	$ 42,333	$ 1,237	$ (482)	$ (9,856)	$ 75,547	$ 51,634	$ 66,446	$ 71,861

Derivative Activities (Details 2) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Derivative assets:
Derivative Assets - Commodity collars, basis swaps and call options	$ 131,450	$ 25,652
Derivative liabilities:
Derivative Liabilities - Commodity collars, basis swaps and call options	(13,764)	(14,759)
Crude Oil [Member] \| Call Option [Member]
Derivative assets:
Derivative Assets - Commodity collars, basis swaps and call options	(31,904)	0
Derivative liabilities:
Derivative Liabilities - Commodity collars, basis swaps and call options	(28,393)	0
Crude Oil [Member] \| Collars [Member]
Derivative assets:
Derivative Assets - Commodity collars, basis swaps and call options	0	66
Derivative liabilities:
Derivative Liabilities - Commodity collars, basis swaps and call options	(12,051)	0
Natural Gas [Member] \| Collars [Member]
Derivative assets:
Derivative Assets - Commodity collars, basis swaps and call options	163,354	26,649
Derivative liabilities:
Derivative Liabilities - Commodity collars, basis swaps and call options	27,032	2,020
Natural Gas [Member] \| Basis Swap [Member]
Derivative assets:
Derivative Assets - Commodity collars, basis swaps and call options	0	(1,063)
Derivative liabilities:
Derivative Liabilities - Commodity collars, basis swaps and call options	$ (352)	$ (16,779)

Derivative Activities (Details 3) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Derivatives that qualify for cash flow hedge accounting :
Assets Carrying Value	$ 173,128	$ 22,062
Net Carrying Value	173,128	22,062
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	17,259	6,738
(Liabilities) Carrying Value	(72,701)	(17,907)
Net Carrying Value	(55,442)	(11,169)
Call Option [Member]
Derivatives that do not qualify for hedge accounting :
(Liabilities) Carrying Value	(60,297)
Net Carrying Value	(60,297)
Collars [Member]
Derivatives that qualify for cash flow hedge accounting :
Assets Carrying Value	173,128	22,062
Net Carrying Value	173,128	22,062
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	17,259	6,673
(Liabilities) Carrying Value	(12,052)
Net Carrying Value	5,207	6,673
Basis Swap [Member]
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value		65
(Liabilities) Carrying Value	(352)	(17,907)
Net Carrying Value	$ (352)	$ (17,842)

Derivative Activities (Details 4) - USD ($) $ in Thousands	12 Months Ended
Derivative Activities (Details 4) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Effects of cash flow hedges and other hedges on accumulated other comprehensive income (loss)
Change in unrealized deferred hedging gains, before tax	$ 165,642	$ 91,059	$ 98,008
Income taxes	(64,662)	(34,180)	(35,453)
Realized Gain Reclassified from OCI into Revenue	64,772	203,119	(63,574)
Income taxes	(24,841)	(75,154)	24,158
Effects of cash flow hedges on accumulated other comprehensive income (loss), total	100,980	56,879	62,555
Effects of cash flow hedges on accumulated other comprehensive income (loss), total	$ 39,931	$ 127,965	$ (39,416)

Derivative Activities (Details 5) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Derivative Activities (Details 5) - USD ($) $ in Thousands	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									$ 49,599	$ 63,393	$ 68,780
Ineffective unrealized and realized gains (losses) recognized income									2,035	3,053	3,081
Derivative Fair Value Income	$ (7,226)	$ 9,981	$ 6,546	$ 42,333	$ 1,237	$ (482)	$ (9,856)	$ 75,547	51,634	66,446	71,861
Call Option [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									(15,895)
Derivative Fair Value Income									(15,895)
Collars [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									65,996	33,859	33,119
Ineffective unrealized and realized gains (losses) recognized income									2,035	3,053	3,519
Derivative Fair Value Income									68,031	36,912	36,638
Swap [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)										63,755	14,395
Ineffective unrealized and realized gains (losses) recognized income											(438)
Derivative Fair Value Income										63,755	13,957
Basis Swap [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									(502)	(34,221)	21,266
Derivative Fair Value Income									$ (502)	$ (34,221)	$ 21,266

Derivative Activities (Details Textuals)	12 Months Ended
Derivative Activities (Details Textuals)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Derivative Activities (Textuals) [Abstract]
Hedged gas collars (in bcf)	192.8
Hedged oil collars	700,000
Call option of oil	3,700,000
Weighted average prices of call option of oil (per barrel)	82.31
Derivative assets liabilities at fair value net	$ 118,000,000
Unrealized pre-tax derivative gain	111,100,000
Unrealized pre-tax derivative gain expected to be reclassified into earnings in 2011	104,300,000
Unrealized gain on cash flow hedging effective portion to be reclassified into earnings in year two	6,800,000
Gains (Losses) in oil and gas sales related to settled hedging transactions	64,800,000	$ 203,100,000	$ 63,600,000
Ineffective unrealized and realized gains (losses) recognized income	2,035,000	$ 3,053,000	$ 3,081,000
Net unrealized pre-tax loss on fair value of the basis swaps	$ 352,000
Number of financial institutions with whom we conduct derivative activities	9
Number of secured financial institutions with whom we conduct derivative activities	9
Collar Oil [Member]
Derivative [Line Items]
Weighted average floor prices	70.00
Weighted average cap prices	80.00
Natural Gas [Member]
Derivative [Line Items]
Weighted average floor prices	5.54
Weighted average cap prices	6.43

Fair Value Measurements (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Values of assets measured at fair value on a nonrecurring basis
Proved natural gas and oil properties, fair value	$ 851,988	$ 1,244
Proved natural gas and oil properties, impairment	469,749	930
Equity investments, fair value	$ 0	2,895
Impairment of equity investment		$ 8,950

Fair Value Measurements (Details 2) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Assets:
Commodity swaps, collars and call options	$ 131,450	$ 25,652
Marketable securities	47,800
Liabilities:
Commodity swaps, collars and call options	(13,764)	(14,759)
Carrying Value [Member]
Assets:
Commodity swaps, collars and call options	131,450	25,652
Marketable securities	47,794	43,554
Liabilities:
Commodity swaps, collars and call options	(13,764)	(14,759)
Long-term debt	(1,960,536)	(1,707,833)
Fair Value [Member]
Assets:
Commodity swaps, collars and call options	131,450	25,652
Marketable securities	47,794	43,554
Liabilities:
Commodity swaps, collars and call options	(13,764)	(14,759)
Long-term debt	$ (2,055,813)	$ (1,842,625)

Fair Value Measurements (Details Textuals)	3 Months Ended			12 Months Ended
Fair Value Measurements (Details Textuals)	Dec. 31, 2010 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Feb. 28, 2011 USD ($)
Fair Value Measurements (Textuals) [Abstract]
Interest and Dividend Income, Securities, Trading or Measured at Fair Value				$ 864,000	$ 487,000	$ 1,500,000
Mark-to-market gain (loss)				11,500,000	10,400,000	$ (19,400,000)
Oil and Gas property impairment	$ 463,244,000	$ 6,505,000	$ 930,000	469,749,000	930,000
Selling price of assets in Barnett Shale properties in North Central Texas							$ 900,000,000
Allowance for uncollectible receivables	5,000,000		$ 2,200,000	$ 5,000,000	2,200,000
Number of financial institutions included in counterparties				9
Number of secured lenders in bank credit facility				9
Impairment of equity investment					$ 8,950,000
Net Book Value Of Oil And Gas Properties Barnett ShaleNet Book Value Of Oil And Gas Properties Barnett Shale	$ 835,000,000			$ 835,000,000

Stock-Based Compensation Plans (Details)	12 Months Ended
Stock-Based Compensation Plans (Details)	Dec. 31, 2010 $ / shares shares	Dec. 31, 2010 USD ($) shares	Dec. 31, 2009 $ / shares USD ($) shares	Dec. 31, 2008 $ / shares USD ($) shares
Stock Option and SARs Activities
Beginning Balance, Shares	7,154,712	7,154,712	7,248,666	7,772,325
Beginning Balance, Weighted Average Exercise Price \| $		$ 31.38	$ 26.15	$ 17.95
Granted	46.09	46.09	36.9	63.18
Granted, Shares	1,394,136	1,394,136	1,714,165	1,159,649
Exercised \| $		$ 20.49	$ 14.31	$ 12.24
Exercised, Shares	(1,883,091)	(1,883,091)	(1,717,584)	(1,590,390)
Expired/forfeited \| $		$ 48.18	$ 40.73	$ 40.82
Expired/forfeited, Shares	(203,918)	(203,918)	(90,535)	(92,918)
Ending Balance, Shares	6,461,839	6,461,839	7,154,712	7,248,666
Ending Balance, Weighted Average Exercise Price \| (per share)	$ 37.20	$ 37.20	$ 31.38	$ 26.15

Stock Based Compensation Plans (Details 1)	12 Months Ended
Stock Based Compensation Plans (Details 1)	Dec. 31, 2010 $ / shares shares	Dec. 31, 2010 USD ($) shares	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Dec. 31, 2007 USD ($)
Outstanding stock options and SARs
Number of outstanding options and SARs \| shares	6,461,839	6,461,839
Weighted-Average Remaining Contractual Life	2.25
Weighted-Average Exercise Price \| (per share)	$ 37.20	$ 37.20	$ 31.38	$ 26.15	$ 17.95
Number of exercisable options and SARs \| shares	3,872,848	3,872,848
Weighted Average Exercise Price	$ 31.82
Range Of Exercise Prices One [Member]
Outstanding stock options and SARs
Excercise price, Minimum	1.29
Excercise price, Maximum	$ 9.99
Number of outstanding options and SARs \| shares	770,056	770,056
Weighted-Average Remaining Contractual Life	1.10
Weighted-Average Exercise Price	$ 3.55
Number of exercisable options and SARs \| shares	770,056	770,056
Weighted Average Exercise Price	$ 3.55
Range Of Exercise Prices Two [Member]
Outstanding stock options and SARs
Excercise price, Minimum	10.00
Excercise price, Maximum	$ 19.99
Number of outstanding options and SARs \| shares	15,435	15,435
Weighted-Average Remaining Contractual Life	4.73
Weighted-Average Exercise Price	$ 19.63
Number of exercisable options and SARs \| shares	15,435	15,435
Weighted Average Exercise Price	$ 19.63
Range Of Exercise Prices Three [Member]
Outstanding stock options and SARs
Excercise price, Minimum	20.00
Excercise price, Maximum	$ 29.99
Number of outstanding options and SARs \| shares	780,219	780,219
Weighted-Average Remaining Contractual Life	0.26
Weighted-Average Exercise Price	$ 24.32
Number of exercisable options and SARs \| shares	780,219	780,219
Weighted Average Exercise Price	$ 24.32
Range Of Exercise Prices Four [Member]
Outstanding stock options and SARs
Excercise price, Minimum	30.00
Excercise price, Maximum	$ 39.99
Number of outstanding options and SARs \| shares	1,958,221	1,958,221
Weighted-Average Remaining Contractual Life	1.94
Weighted-Average Exercise Price	$ 34.49
Number of exercisable options and SARs \| shares	1,373,383	1,373,383
Weighted Average Exercise Price	$ 34.60
Range Of Exercise Prices Five [Member]
Outstanding stock options and SARs
Excercise price, Minimum	40.00
Excercise price, Maximum	$ 49.99
Number of outstanding options and SARs \| shares	1,938,906	1,938,906
Weighted-Average Remaining Contractual Life	3.90
Weighted-Average Exercise Price	$ 44.69
Number of exercisable options and SARs \| shares	293,309	293,309
Weighted Average Exercise Price	$ 42.36
Range Of Exercise Prices Six [Member]
Outstanding stock options and SARs
Excercise price, Minimum	50.00
Excercise price, Maximum	$ 59.99
Number of outstanding options and SARs \| shares	634,837	634,837
Weighted-Average Remaining Contractual Life	1.94
Weighted-Average Exercise Price	$ 58.32
Number of exercisable options and SARs \| shares	404,805	404,805
Weighted Average Exercise Price	$ 58.53
Range Of Exercise Prices Seven [Member]
Outstanding stock options and SARs
Excercise price, Minimum	60.00
Excercise price, Maximum	$ 69.99
Number of outstanding options and SARs \| shares	18,927	18,927
Weighted-Average Remaining Contractual Life	2.42
Weighted-Average Exercise Price	$ 65.56
Number of exercisable options and SARs \| shares	11,356	11,356
Weighted Average Exercise Price	$ 65.56
Range Of Exercise Prices Eight [Member]
Outstanding stock options and SARs
Excercise price, Minimum	70.00
Excercise price, Maximum	$ 75.00
Number of outstanding options and SARs \| shares	345,238	345,238
Weighted-Average Remaining Contractual Life	2.29
Weighted-Average Exercise Price	$ 75.00
Number of exercisable options and SARs \| shares	224,285	224,285
Weighted Average Exercise Price	$ 75.00

Stock Based Compensation Plans (Details 2)	12 Months Ended
Stock Based Compensation Plans (Details 2)	Dec. 31, 2010 $ / shares	Dec. 31, 2010	Dec. 31, 2010 USD ($)	Dec. 31, 2009 $ / shares	Dec. 31, 2009	Dec. 31, 2009 USD ($)	Dec. 31, 2008 $ / shares	Dec. 31, 2008	Dec. 31, 2008 USD ($)
Weighted average grant date fair value of SARs
Weighted average exercise price per share	46.09		46.09	36.9		36.90	63.18		63.18
Expected annual dividends per share		0.35%			0.44%			0.26%
Expected life in years		3.6			3.5			3.5
Expected volatility		49.00%			58.00%			41.00%
Risk-free interest rate		1.60%			1.50%			2.40%
Weighted average grant date fair value of SARs granted			17.01			15.42			20.58

Stock Based Compensation Plans (Details 3) - USD ($)	12 Months Ended
Stock Based Compensation Plans (Details 3) - USD ($)	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Non-vested restricted stock outstanding
Granted	$ 45.83	$ 39.99	$ 63.00
Granted, Shares	413,422	685,578	362,313
Vested	$ 46.90	$ 40.91	$ 37.54
Vested, Shares	(439,361)	(521,536)	(438,058)
Forfeited	$ 46.04	$ 40.83	$ 38.87
Forfeited, Shares	(18,499)	(10,400)	(14,368)
Non-vested shares outstanding	$ 45.64	$ 48.50	$ 30.42
Non-vested shares outstanding, Shares	582,751	627,189	473,547

Stock Based Compensation Plans (Details Textuals)	3 Months Ended				12 Months Ended
Stock Based Compensation Plans (Details Textuals)	Dec. 31, 2010 USD ($) shares	Mar. 31, 2010 USD ($)	Dec. 31, 2009 USD ($) shares	Sep. 30, 2009 USD ($)	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares	Dec. 31, 2008 USD ($) $ / shares shares	Dec. 31, 2007 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3
Expiration term of stock options					5
Termination costs	$ 514,000	$ 7,938,000	$ 1,639,000	$ 840,000	$ 8,452,000	$ 2,479,000
Stock based compensation plans (Textuals) [Abstract]
Incremental compensation					2,800,000	332,000
stock-based compensation expense					44,700,000	$ 41,800,000	$ 31,200,000
Cash received upon exercise of stock options/SARs Award					$ 5,900,000
Number of Active Stock Based plans					2
Number of stock option and SARs outstanding \| shares	6,461,839		7,154,712		6,461,839	7,154,712	7,248,666	7,772,325
Number of stock option outstanding \| shares	785,000				785,000
Number of SARs outstanding \| shares	5,700,000				5,700,000
Total intrinsic value of stock options and SARs exercised					$ 50,600,000	$ 50,900,000	$ 67,900,000
Aggregate intrinsic value of the awards outstanding	$ 71,000,000				71,000,000
Aggregate intrinsic value of the awards exercisable					$ 63,500,000
Weighted average remaining contractual life of stock option/SARs awards					1.3
Number of fully vested awards and awards expected to vest \| shares	6,300,000				6,300,000
Weighted average remaining contractual life of fully vested awards and awards expected to vest					2.2
Weighted average exercise price of fully vested awards and awards expected to vest	$ 36.91				$ 36.91
Aggregate intrinsic value of fully vested awards and awards expected to vest	70,400,000				70,400,000
Unrecognized compensation of fully vested awards and awards expected to vest	25,500,000				$ 25,500,000
Weighted average period					1.8
Shares granted to employees and directors \| shares					413,422	685,578	362,313
Shares granted to employees \| shares					392,000	663,300	347,600
Shares granted to directors \| shares					21,000	22,700	14,400
Vesting period of shares granted to employees					3	3	3
SARs granted average price \| $ / shares					$ 45.83	$ 39.99	$ 63.00
Compensation cost related to restricted stock grants					$ 20,500,000	$ 19,700,000	$ 14,700,000
Unrecognized compensation cost related to restricted stock grants	$ 23,300,000				$ 23,300,000
Unrecognized compensation cost expected to be recognized (in years)					1.8
Proceeds received from the sale of stock held in deferred compensation plan					$ 5,200,000
Percentage of employees contribution	75.00%				75.00%
Maximum percentage of employers contribution in cash					6.00%
Minimum period of service for contribution to fully vest					2
Employer contribution to the plan					$ 3,100,000	$ 3,200,000	2,700,000
Shares held in rabbi trust total \| shares	2,900,000		2,700,000		2,900,000	2,700,000
Non-cash, Mark-to-market income (loss) related to deferred compensation plan					$ 10,200,000	$ (31,100,000)	24,700,000
Vested shares held in rabbi trust \| shares	2,300,000		2,100,000		2,300,000	2,100,000
Stock appreciation rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period					3
Expiration term of stock options					5
Director Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized \| shares	450,000				450,000
Share Based compensation Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Operating expense					$ 2,300,000	$ 2,600,000	2,800,000
Exploration expense					4,200,000	4,700,000	4,100,000
General and administrative expense					34,200,000	33,300,000	$ 23,800,000
Termination costs					$ 2,800,000	$ 332,000

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Net cash provided from continuing operations included:
Income taxes (refunded from) paid to taxing authorities	$ (1,359)	$ 170	$ 4,298
Interest paid	116,766	108,685	93,954
Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net	(6,523)	6,131	$ 4,647
Unproved property purchased with stock	$ 20,000	33,726
Shares issued in lieu of bonuses		$ 6,312

Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2010 USD ($)
Future minimum rental commitments
2011	$ 9,913
2012	10,054
2013	7,067
2014	6,395
2015	6,368
Thereafter	27,833
Sublease rentals	(615)
Operating Leases Future Minimum Payments Due Including Sub lease	$ 67,015

Commitments and Contingencies (Details 1) $ in Thousands	Dec. 31, 2010 USD ($)
Transportation Commitments
2011	$ 68,587
2012	65,824
2013	64,794
2014	61,351
2015	59,870
Thereafter	381,697
Total	$ 702,123

Commitments and Contingencies (Details Textuals)	1 Months Ended				12 Months Ended
Commitments and Contingencies (Details Textuals)	Nov. 30, 2013	Nov. 30, 2012	Sep. 30, 2011	Feb. 28, 2011	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)
Commitments And Contingencies (Textuals) [Abstract]
Rent expenses under operating leases								$ 18,500,000	$ 18,800,000	$ 15,400,000
Minimum natural gas production, Mmbtu per day in Appalachia								284,905
Incremental increase in gas production, Mmbtu per day in Appalachia	75,000	108,000	150,000	350,000				683,000
Number of drilling rigs used under drilling contracts								8
Period of drilling contracts in years								3
Drilling contracts, future minimum commitments due for 2011								$ 72,900,000
Drilling contracts, future minimum commitments due for 2012								53,700,000
Drilling contracts, future minimum commitments due for 2013								14,700,000
Drilling contracts, future minimum commitments due for 2014								$ 896,000
Number of rigs custom built for Marcellus Shale program								6
Maximum penalties on early termination of drilling contracts								$ 93,400,000
Volume of Mmbtu per day to be delivered under sales agreement								30,000
Period of sales agreement								5
Remaining volumes to be delivered under sales agreement (in Bcf)								24.6
Total amount related to the agreement to purchase seismic data					$ 645,000	$ 6,000,000	$ 11,800,000
Period of lease agreement for hydraulic fracturing services								2
Amount of lease agreement for hydraulic fracturing services						$ 40,000,000	$ 48,000,000
Minimum remaining terms of leases on undeveloped acreage, in years								3
Maximum remaining terms of leases on undeveloped acreage, in years								5

Major Customers (Details)	12 Months Ended
Major Customers (Details)	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Major Customers (Textuals) [Abstract]
Number of customers accounted for more than 10% of total Oil and Gas revenues	0	0	1

Equity Method Investments (Details) - USD ($)	1 Months Ended	12 Months Ended
Equity Method Investments (Details) - USD ($)	May 31, 2007	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2006
Schedule of Equity Method Investments [Line Items]
Impairment of equity investment			$ 8,950,000
Equity in the losses/earnings of investment		$ (1,482,000)	(13,699,000)	$ (218,000)
Net book value of investment		$ 155,105,000	146,809,000
Whipstock Natural Gas Services, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Impairment of equity investment			9,000,000
Percentage of interest acquired		50.00%			50.00%
Cash contributed for investment					$ 11,700,000
Equity in the losses/earnings of investment		$ 2,200,000	13,100,000	479,000
Cash distribution from investment			301,000	1,800,000
Reduction in equity to eliminate the profit from gathering and transportation fees		1,100,000	422,000	1,800,000
Net book value of investment		$ 1,700,000
Nora Gathering, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Percentage of interest acquired	50.00%	50.00%
Cash contributed for investment	$ 94,700,000
Equity in the losses/earnings of investment		$ 684,000	629,600	261,000
Reduction in equity to eliminate the profit from gathering and transportation fees		8,800,000	7,000,000	$ 4,800,000
Net book value of investment		153,400,000
Contribution by Range and EQT towards Nora Gathering		$ 0	$ 6,400,000

Office Closing and Exit Activities (Details) - USD ($)	3 Months Ended			12 Months Ended
Office Closing and Exit Activities (Details) - USD ($)	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Dec. 31, 2010	Dec. 31, 2009
Exit activities included in accrued liabilities in consolidated balance sheet
Beginning Balance	$ 1,568,000			$ 1,568,000	$ 0
Accrued one-time termination costs	$ 5,100,000	$ 635,000	$ 1,300,000	5,138,000	1,895,000
Office lease				514,000	252,000
Payments				(6,128,000)	(579,000)
Ending Balance		$ 1,568,000		$ 1,092,000	$ 1,568,000

Office Closing and Exit Activities (Details Textuals) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Dec. 31, 2010	Dec. 31, 2009
Restructuring Reserve [Line Items]
Increasing in termination costs for stock compensation expense	$ 514,000	$ 7,938,000	$ 1,639,000	$ 840,000	$ 8,452,000	$ 2,479,000
Office Closing and Exit Activities (Textuals)
Accrued severance costs		5,100,000	$ 635,000	$ 1,300,000	$ 5,138,000	$ 1,895,000
Employee Severance [Member]
Restructuring Reserve [Line Items]
Increasing in termination costs for stock compensation expense		$ 2,800,000

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Revenues and other income:
Natural gas, NGL and oil sales	$ 246,503	$ 219,560	$ 206,784	$ 236,760	$ 242,087	$ 202,122	$ 192,523	$ 203,189	$ 909,607	$ 839,921	$ 1,226,560
Transportation and gathering	(65)	(1,634)	674	2,093	(3,605)	2,444	2,152	(505)	1,068	486	4,577
Derivative fair value income	(7,226)	9,981	6,546	42,333	1,237	(482)	(9,856)	75,547	51,634	66,446	71,861
Gain on the sale of assets	(1,514)	67	10,176	68,868	10,374	32	(29)	36	77,597	10,413	20,166
Other	1,020	(1,013)	637	(1,575)	(3,262)	(475)	(4,358)	(1,830)	(931)	(9,925)	1,509
Total revenues and other income	238,718	226,961	224,817	348,479	246,831	203,641	180,432	276,437	1,038,975	907,341	1,324,673
Costs and expenses:
Direct operating	36,500	34,287	29,775	31,040	31,731	31,111	34,828	35,541	131,602	133,211	142,387
Production and ad valorem taxes	8,619	8,873	8,090	8,070	8,748	7,600	7,564	8,257	33,652	32,169	55,172
Exploration	16,743	15,236	14,473	14,635	10,876	10,902	11,368	13,339	61,087	46,485	67,690
Abandonment and impairment of unproved properties	23,533	20,534	13,497	12,407	28,959	24,053	40,954	19,572	69,971	113,538	47,355
General and administrative	40,042	36,523	35,836	28,170	31,378	29,928	29,103	24,910	140,571	115,319	92,308
Termination costs	514			7,938	1,639	840			8,452	2,479
Deferred compensation plan	14,978	(5,347)	(14,135)	(5,712)	1,438	16,445	756	12,434	(10,216)	31,073	(24,689)
Interest expense	36,320	33,806	30,779	30,287	30,550	30,633	29,555	26,629	131,192	117,367	99,748
Loss on early extinguishment of debt		5,351							5,351
Depletion, depreciation and amortization	92,116	91,768	90,997	88,626	103,261	97,208	88,713	84,320	363,507	373,502	299,831
Impairment of proved properties	463,244			6,505	930				469,749	930
Total costs and expenses	732,609	241,031	209,312	221,966	249,510	248,720	242,841	225,002	1,404,918	966,073	779,802
(Loss) income before income taxes	(493,891)	(14,070)	15,505	126,513	(2,679)	(45,079)	(62,409)	51,435	(365,943)	(58,732)	544,871
Income tax (benefit) expense
Current	(826)	(10)			(560)	(695)	619		(836)	(636)	4,268
Deferred	(175,346)	(5,892)	6,453	48,934	14,658	(14,566)	(23,145)	18,827	(125,851)	(4,226)	189,563
Total tax (benefit) provision	(176,172)	(5,902)	6,453	48,934	14,098	(15,261)	(22,526)	18,827	(126,687)	(4,862)	193,831
Net (loss) income	$ (317,719)	$ (8,168)	$ 9,052	$ 77,579	$ (16,777)	$ (29,818)	$ (39,883)	$ 32,608	$ (239,256)	$ (53,870)	$ 351,040
(Loss) income per common share:
Basic	$ (2.02)	$ (0.05)	$ 0.06	$ 0.50	$ (0.11)	$ (0.19)	$ (0.26)	$ 0.21	$ (1.53)	$ (0.35)	$ 2.32
Diluted	$ (2.02)	$ (0.05)	$ 0.06	$ 0.48	$ (0.11)	$ (0.19)	$ (0.26)	$ 0.21	$ (1.53)	$ (0.35)	$ 2.25

Selected Quarterly Financial Data (Unaudited) (Details 1)	Dec. 31, 2010	May 31, 2007	Dec. 31, 2006
Whipstock Natural Gas Services, LLC [Member]
Principal Unconsolidated Investees
Ownership	50.00%		50.00%
Drilling services	Drilling services
Nora Gathering, LLC [Member]
Principal Unconsolidated Investees
Ownership	50.00%	50.00%
Gas gathering and transportation	Gas gathering and transportation

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Natural gas and oil properties:
Properties subject to depletion	$ 5,749,620	$ 5,534,204	$ 5,271,020
Unproved properties	811,834	774,503	757,960
Total	6,561,454	6,308,707	6,028,980
Accumulated depreciation, depletion and amortization	(1,639,397)	(1,409,888)	(1,186,934)
Net capitalized costs	$ 4,922,057	$ 4,898,819	$ 4,842,046

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details 1) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2010	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Acquisitions:
Unproved leasehold	$ 3,700	$ 3,697		$ 99,446
Proved oil and gas properties		130,767		251,471
Asset retirement obligations		556		251
Acreage purchases		166,677	$ 176,867	494,341
Development		784,153	497,702	729,268
Exploration:
Drilling		50,737	57,121	133,116
Expense		56,879	42,082	63,560
Stock-based compensation expense		4,209	4,817	4,130
Gas gathering facilities:
Development		20,726	29,524	47,056
Subtotal		1,218,401	808,113	1,822,639
Asset retirement obligations		(6,523)	6,131	4,647
Total costs incurred		$ 1,211,878	$ 814,244	$ 1,827,286

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details 2)	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Crude Oil [Member]
Proved developed and undeveloped reserves:
Begining Balance	34,082	49,487	48,912
Revisions	(2,672)	(1,536)	(4,946)
Extensions, discoveries and additions	4,663	3,479	10,198
Purchases	0
Property sales	(10,865)	(14,791)	(1,592)
Production	(1,969)	(2,557)	(3,085)
Ending Balance	23,239	34,082	49,487
Proved Developed Reserves
Proved developed reserves	17,050	20,626	32,611
Proved Undeveloped Reserves
Proved Undeveloped Reserves	6,189	13,457	16,876
Natural Gas [Member]
Proved developed and undeveloped reserves:
Begining Balance	2,614,717	2,213,546	1,832,797
Revisions	3,599	(37,497)	(23,397)
Extensions, discoveries and additions	1,089,632	620,114	423,354
Purchases	124,981		95,262
Property sales	(124,369)	(50,797)	(147)
Production	(142,034)	(130,649)	(114,323)
Ending Balance	3,566,526	2,614,717	2,213,546
Proved Developed Reserves
Proved developed reserves	1,762,766	1,445,705	1,337,978
Proved Undeveloped Reserves
Proved Undeveloped Reserves	1,803,760	1,169,012	875,567
Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped reserves:
Begining Balance	51,588	23,849	17,748
Revisions	26,832	8,434	1,791
Extensions, discoveries and additions	48,792	21,492	5,643
Purchases	0		53
Property sales	0
Production	(4,490)	(2,187)	(1,386)
Ending Balance	122,722	51,588	23,849
Proved Developed Reserves
Proved developed reserves	53,071	26,205	16,398
Proved Undeveloped Reserves
Proved Undeveloped Reserves	69,651	25,382	7,451
Natural Gas Equivalents [Member]
Proved developed and undeveloped reserves:
Begining Balance	3,128,739	2,653,565	2,232,762
Revisions	148,558	3,890	(42,333)
Extensions, discoveries and additions	1,410,359	769,939	518,404
Purchases	124,981		95,578
Property sales	(189,558)	(139,543)	(9,701)
Production	(180,789)	(159,112)	(141,145)
Ending Balance	4,442,290	3,128,739	2,653,565
Proved Developed Reserves
Proved developed reserves	2,183,488	1,726,696	1,632,032
Proved Undeveloped Reserves
Proved Undeveloped Reserves	2,258,802	1,402,043	1,021,531

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details 3)	12 Months Ended
	Dec. 31, 2010
Proved Undeveloped Reserves
Beginning proved undeveloped reserves	1,402,043
Undeveloped reserves transferred to developed	(191,220)
Revisions	(75,685)
Purchase/Sales	(25,643)
Extension and discoveries	1,149,307
Ending proved undeveloped reserves	2,258,802

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future cash inflows	$ 19,676,630	$ 11,969,906
Future costs
Production	(4,305,292)	(3,371,762)
Development	(2,855,407)	(1,877,330)
Future net cash flows before income taxes	12,515,931	6,720,814
Future income tax expense	(3,923,264)	(1,767,965)
Total future net cash flows before 10% discount	8,592,667	4,952,849
10% annual discount	(5,113,541)	(2,861,760)
Standardized measure of discounted future net cash flows	$ 3,479,126	$ 2,091,089

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details 5) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Changes in Standardized Measure Discounted future net cash flows
Beginning of period	$ 2,091,089	$ 2,581,380	$ 3,666,363
Revisions of previous estimates:
Changes in prices	957,994	(992,809)	(1,675,703)
Revisions in quantities	190,874	4,124	(65,931)
Changes in future development costs	(474,058)	(375,344)	(688,259)
Accretion of discount	259,280	340,025	520,482
Net change in income taxes	(666,517)	317,158	719,595
Purchases of reserves in place	160,580		148,857
Additions to proved reserves from extensions discoveries and improved recovery	1,812,077	816,278	807,386
Production	(744,354)	(673,907)	(1,029,001)
Development costs incurred during the period	298,624	316,523	333,979
Sales of gas and oil	(243,551)	(147,942)	(15,109)
Timing and other	(162,912)	(94,397)	(141,279)
End of period	$ 3,479,126	$ 2,091,089	$ 2,581,380

Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Details Textuals) $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($) shares	Dec. 31, 2008 USD ($)
Supplemetal Information on Natural Gas and Oil Exploration Development and Production Activities (Textuals) [Abstract]
Stock Issued to Purchase acreage, Shares \| shares					380,229
Stock Issued to Purchase acreage, Value					$ 20,000	$ 223,900
Increase in depletion, depreciation and amortization expense, before tax					3,400
Percentage of proved resources reviewed by consultants				90.00%
Variance in reserve estimates				less than 5%
Undeveloped reserves transferred to developed reserves				$ 192,000
Estimated future development costs	$ 924,800	$ 830,800	$ 476,900
Volume of Mmcfe of reserves that have been reported for five or more years included in proved undeveloped reserves, approximately				2,388
Percentage of total proved undeveloped reserves				<1%
Discount rate applying for resulting future net cash flows				10.00%
Coversion rate of Oil and NGLs to mcfe				one barrel equals six mcf
Period for which the reserves have been reported to be included in proved undeveloped reserves				five or more years
Crude Oil and NGL, Per Barrel [Member]
Average Sales Price and Production Costs Per Unit of Production
Benchmark price used for calculating average realized prices				$ 79,810	60,850	44,600
Natural Gas, Per Thousand Cubic Feet [Member]
Average Sales Price and Production Costs Per Unit of Production
Benchmark price used for calculating average realized prices				4,380	3,870	5,710
Crude Oil [Member]
Average Sales Price and Production Costs Per Unit of Production
Estimate reserve information average realized prices				$ 72,510	$ 54,650	$ 42,760
Increase (Decrease) in proved reserves				(2,672)	(1,536)	(4,946)
Natural Gas Liquids Reserves [Member]
Average Sales Price and Production Costs Per Unit of Production
Estimate reserve information average realized prices				$ 39,140	$ 34,050	$ 25,000
Increase (Decrease) in proved reserves				26,832	8,434	1,791
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production
Estimate reserve information average realized prices				$ 3,700	$ 3,190	$ 5,230
Increase (Decrease) in proved reserves				3,599	(37,497)	(23,397)

Label	Element	Value
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	us-gaap_ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsNonvestedNumber	563,660
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	us-gaap_ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsNonvestedWeightedAverageGrantDateFairValue	$ 44.81

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2010	Dec. 31, 2009
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Trading securities held in our deferred compensation plans	$ 47,794	$ 43,554
Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	(60,297)
Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	178,335	28,735
Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives - basis swaps	(352)	(17,842)
Quoted Prices in Active Markets for Identical Assets [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Trading securities held in our deferred compensation plans	47,794	43,554
Quoted Prices in Active Markets for Identical Assets [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	0
Quoted Prices in Active Markets for Identical Assets [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	0	0
Quoted Prices in Active Markets for Identical Assets [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives - basis swaps	0	0
Significant Other Observable Inputs [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Trading securities held in our deferred compensation plans	0	0
Significant Other Observable Inputs [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	(60,297)
Significant Other Observable Inputs [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	178,335	28,735
Significant Other Observable Inputs [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives - basis swaps	(352)	(17,842)
Significant Unobservable Inputs [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Trading securities held in our deferred compensation plans	0	0
Significant Unobservable Inputs [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	0
Significant Unobservable Inputs [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives	0	0
Significant Unobservable Inputs [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivatives - basis swaps	$ 0	$ 0