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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2011	Feb. 17, 2012	Jun. 30, 2011
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, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
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			$ 8,686,292,000
Entity Common Stock Shares Outstanding		161,748,938

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 92	$ 2,848
Accounts receivable, less allowance for doubtful accounts of $4,015 and $5,001	127,180	88,536
Assets of discontinued operations	0	877,579
Unrealized derivative gain	173,921	123,255
Inventory and other	14,070	21,352
Total current assets	315,263	1,113,570
Unrealized derivative gain	77,579	0
Equity method investments	138,130	155,105
Natural gas and oil properties, successful efforts method	6,784,027	5,390,391
Accumulated depletion and depreciation	(1,626,461)	(1,306,378)
Natural gas and oil properties, successful efforts method, net	5,157,566	4,084,013
Transportation and field assets	123,349	134,980
Accumulated depreciation and amortization	(70,671)	(60,931)
Transportation and field assets, net	52,678	74,049
Other assets	104,254	84,977
Total assets	5,845,470	5,511,714
Current liabilities:
Accounts payable	311,369	289,109
Asset retirement obligations	5,005	4,020
Accrued liabilities	109,109	71,935
Liabilities of discontinued operations	653	34,237
Deferred tax liability	56,595	11,848
Accrued interest	29,201	32,189
Unrealized derivative loss	0	352
Total current liabilities	511,932	443,690
Bank debt	187,000	274,000
Subordinated notes	1,787,967	1,686,536
Deferred tax liability	710,490	672,041
Unrealized derivative loss	173	13,412
Liabilities of discontinued operations	0	3,901
Deferred compensation liability	169,188	134,488
Asset retirement obligations and other liabilities	86,300	59,885
Total liabilities	3,453,050	3,287,953
Commitments and contingencies
Stockholders' Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding
Common stock, $0.01 par, 475,000,000 shares authorized, 161,302,973 issued at December 31, 2011 and 160,113,608 issued at December 31, 2010	1,613	1,601
Common stock held in treasury, 171,426 shares at December 31, 2011 and 204,556 shares at December 31, 2010	(6,343)	(7,512)
Additional paid-in capital	1,866,554	1,820,503
Retained earnings	373,969	341,699
Accumulated other comprehensive income	156,627	67,470
Total stockholders' equity	2,392,420	2,223,761
Total liabilities and stockholders' equity	$ 5,845,470	$ 5,511,714

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 4,015	$ 5,001
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued
Preferred stock, shares outstanding
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	161,302,973	160,113,608
Common stock held in treasury, shares	171,426	204,556

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other income:
Natural gas, NGLs and oil sales	$ 331,720	$ 304,230	$ 285,353	$ 251,963	$ 231,879	$ 203,255	$ 187,523	$ 200,633	$ 1,173,266	$ 823,290	$ 751,749
Derivative fair value income	(37,879)	65,761	53,039	(40,834)	(7,226)	9,981	6,546	42,333	40,087	51,634	66,446
Gain on the sale of assets	3,540	203	(1,622)	139	(1,514)	67	10,176	67,913	2,260	76,642	10,413
Other	2,686	442	(1,475)	1,390	914	(2,650)	1,300	506	3,043	70	(9,442)
Total revenues and other income	300,067	370,636	335,295	212,658	224,053	210,653	205,545	311,385	1,218,656	951,636	819,166
Costs and expenses:
Direct operating	25,918	29,828	28,509	28,717	27,732	25,535	21,171	21,836	112,972	96,274	98,251
Transportation, gathering and compression	34,576	32,431	28,666	25,082	20,009	15,498	14,370	12,960	120,755	62,837	37,185
Production and ad valorem taxes	5,920	7,317	7,550	6,879	6,999	6,903	5,663	6,542	27,666	26,107	25,536
Exploration	24,982	17,606	11,592	27,187	16,722	15,225	14,420	14,139	81,367	60,506	44,276
Abandonment and impairment of unproved properties	27,639	16,627	18,900	16,537	19,025	14,435	9,727	6,551	79,703	49,738	36,935
General and administrative	42,205	35,907	39,120	33,959	40,042	36,523	35,836	28,170	151,191	140,571	115,319
Termination costs					514			7,938		8,452	2,479
Deferred compensation plan	9,640	8,717	(5,778)	30,630	14,978	(5,347)	(14,135)	(5,712)	43,209	(10,216)	31,073
Interest expense	34,709	34,181	31,383	24,779	25,100	23,363	21,271	20,931	125,052	90,665	75,261
Loss on early extinguishment of debt		(4)	18,580			5,351			18,576	5,351
Depletion, depreciation and amortization	97,092	93,619	78,294	72,216	72,888	69,730	67,813	64,807	341,221	275,238	267,148
Impairment of proved properties		38,681						6,505	38,681	6,505	930
Total costs and expenses	302,681	314,910	256,816	265,986	244,009	207,216	176,136	184,667	1,140,393	812,028	734,393
Income from continuing operations before income taxes	(2,614)	55,726	78,479	(53,328)	(19,956)	3,437	29,409	126,718	78,263	139,608	84,773
Income tax expense (benefit)
Current	636	(7)	8		(826)	(10)			637	(836)	(636)
Deferred	(425)	22,547	32,695	(19,897)	(9,823)	794	11,763	49,012	34,920	51,746	46,429
Total income tax (benefit) expense	211	22,540	32,703	(19,897)	(10,649)	784	11,763	49,012	35,557	50,910	45,793
Income from continuing operations	(2,825)	33,186	45,776	(33,431)	(9,307)	2,653	17,646	77,706	42,706	88,698	38,980
Discontinued operations, net of taxes	(164)	1,569	5,517	8,398	(308,412)	(10,821)	(8,594)	(127)	15,320	(327,954)	(92,850)
Net income (loss)	$ (2,989)	$ 34,755	$ 51,293	$ (25,033)	$ (317,719)	$ (8,168)	$ 9,052	$ 77,579	$ 58,026	$ (239,256)	$ (53,870)
Income (loss) per common share:
Basic-income from continuing operations	$ (0.02)	$ 0.21	$ 0.28	$ (0.21)	$ (0.06)	$ 0.02	$ 0.11	$ 0.49	$ 0.26	$ 0.56	$ 0.25
-discontinued operations		0.01	0.04	0.05	(1.96)	(0.07)	(0.05)		0.10	(2.09)	(0.6)
-net income (loss)	(0.02)	0.22	0.32	(0.16)	(2.02)	(0.05)	0.06	0.49	0.36	(1.53)	(0.35)
Diluted-income from continuing operations	(0.02)	0.20	0.28	(0.21)	(0.06)	0.02	0.11	0.48	0.26	0.55	0.24
-discontinued operations		0.01	0.04	0.05	(1.96)	(0.07)	(0.05)		0.10	(2.07)	(0.58)
-net income (loss)	$ (0.02)	$ 0.21	$ 0.32	$ (0.16)	$ (2.02)	$ (0.05)	$ 0.06	$ 0.48	$ 0.36	$ (1.52)	$ (0.34)
Weighted average common shares outstanding:
Basic									158,030	156,874	154,514
Diluted									159,441	158,428	158,778

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements of Comprehensive Income (Loss) [Abstract]
Net income (loss)	$ 58,026	$ (239,256)	$ (53,870)
Other comprehensive income (loss):
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss), net of taxes	(82,196)	(39,931)	(127,965)
Change in unrealized deferred hedging gains (losses), net of taxes	171,353	100,980	56,879
Total comprehensive income (loss)	$ 147,183	$ (178,207)	$ (124,956)

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

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+ Details

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

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+ Details

- Definition

Net of tax effect change in accumulated gains and losses from derivative instruments designated and qualifying as the effective portion of cash flow hedges after taxes. A cash flow hedge is a hedge of the exposure to variability in the cash flows of a recognized asset or liability or a forecasted transaction that is attributable to a particular risk. The change includes an entity's share of an equity investee's increase or decrease in deferred hedging gains or losses. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.

+ References

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+ Details

- Definition

Change in accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges, net of tax effect. The after tax effect change includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

+ References

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+ Details

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating activities:
Net income (loss)	$ 58,026	$ (239,256)	$ (53,870)
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
(Gain) loss from discontinued operations	(15,320)	327,954	92,850
Loss (gain) from equity method investments, net of distributions	16,871	(7,366)	6,693
Deferred income tax expense	34,920	51,746	46,429
Depletion, depreciation and amortization and proved property impairment	379,902	281,743	268,078
Exploration dry hole costs	3,888	3,700	2,159
Mark-to-market on natural gas and oil derivatives not designated as hedges (gain) loss	(15,762)	2,086	115,909
Abandonment and impairment of unproved properties	79,703	49,738	36,935
Unrealized derivative (gain) loss	(2,183)	(2,387)	1,696
Allowance for bad debts	946	3,608	1,351
Amortization of deferred financing costs, loss on extinguishment of debt and other	25,458	10,072	8,755
Deferred and stock-based compensation	86,979	34,964	73,402
Gain on the sale of assets and other	(2,259)	(76,642)	(10,413)
Changes in working capital:
Accounts receivable	(52,112)	(6,512)	13,396
Inventory and other	865	(333)	(1,463)
Accounts payable	738	2,867	(44,765)
Accrued liabilities and other	9,540	(2,096)	(2,935)
Net cash provided from continuing operations	610,200	433,886	554,207
Net cash provided from discontinued operations	21,437	79,436	37,468
Net cash provided from operating activities	631,637	513,322	591,675
Investing activities:
Additions to natural gas and oil properties	(1,199,545)	(732,860)	(356,329)
Additions to field service assets	(11,607)	(14,944)	(33,098)
Acreage and proved property purchases	(226,500)	(296,503)	(139,288)
Investment in equity method investments and other assets		(45)	7,076
Proceeds from disposal of assets	53,926	327,765	234,076
Purchase of marketable securities held by the deferred compensation plan	(25,388)	(17,670)	(7,470)
Proceeds from the sales of marketable securities held by the deferred compensation plan	20,410	19,572	6,079
Net cash used in investing activities from continuing operations	(1,388,704)	(714,685)	(288,954)
Net cash provided from (used in) investing activities from discontinued operations	840,723	(84,173)	(184,853)
Net cash used in investing activities	(547,981)	(798,858)	(473,807)
Financing activities:
Borrowing on credit facilities	887,826	1,055,000	707,000
Repayment on credit facilities	(974,826)	(1,105,000)	(1,076,000)
Issuance of subordinated notes	500,000	500,000	285,201
Repayment of subordinated notes	(413,697)	(202,458)
Dividends paid	(25,756)	(25,574)	(25,169)
Debt issuance costs	(22,003)	(9,600)	(6,399)
Issuance of common stock	619	5,903	12,737
Change in cash overdrafts	(51,474)	64,100	(22,370)
Proceeds from the sales of common stock held by the deferred compensation plan	12,899	5,246	7,201
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases			(55)
Net cash (used in) provided from financing activities	(86,412)	287,617	(117,854)
(Decrease) increase in cash and cash equivalents	(2,756)	2,081	14
Cash and cash equivalents at beginning of year	2,848	767	753
Cash and cash equivalents at end of year	$ 92	$ 2,848	$ 767

Consolidated Statement of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Common stock	Treasury common stock	Additional paid-in capital	Retained earnings	Accumulated other comprehensive income (loss)
Balance at Dec. 31, 2008	$ 2,451,342	$ 1,556	$ (8,557)	$ 1,695,268	$ 685,568	$ 77,507
Balance, Shares at Dec. 31, 2008		155,609
Issuance of common stock	57,601	$ 27		57,574
Issuance of common stock, shares		2,727
Stock-based compensation expense	19,771			19,771
Common dividends declared ($0.16 per share)	(25,169)				(25,169)
Treasury stock issuance			593	(593)
Other comprehensive income	(71,086)					(71,086)
Net income (loss)	(53,870)				(53,870)
Balance at Dec. 31, 2009	2,378,589	$ 1,583	(7,964)	1,772,020	606,529	6,421
Balance, Shares at Dec. 31, 2009		158,336
Issuance of common stock	26,156	$ 18		26,138
Issuance of common stock, shares		1,778
Stock-based compensation expense	22,797			22,797
Common dividends declared ($0.16 per share)	(25,574)				(25,574)
Treasury stock issuance			452	(452)
Other comprehensive income	61,049					61,049
Net income (loss)	(239,256)				(239,256)
Balance at Dec. 31, 2010	2,223,761	$ 1,601	(7,512)	1,820,503	341,699	67,470
Balance, Shares at Dec. 31, 2010		160,114
Issuance of common stock	8,882	$ 12		8,870
Issuance of common stock, shares		1,189
Stock-based compensation expense	26,674			26,674
Tax benefit of stock compensation	11,676			11,676
Common dividends declared ($0.16 per share)	(25,756)				(25,756)
Treasury stock issuance			1,169	(1,169)
Other comprehensive income	89,157					89,157
Net income (loss)	58,026				58,026
Balance at Dec. 31, 2011	$ 2,392,420	$ 1,613	$ (6,343)	$ 1,866,554	$ 373,969	$ 156,627
Balance, Shares at Dec. 31, 2011		161,303

Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Common dividends declared	$ 0.16	$ 0.16	$ 0.16
Retained earnings
Common dividends declared	$ 0.16	$ 0.16	$ 0.16

Summary of Organization and Nature of Business

12 Months Ended

Dec. 31, 2011

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, 2011

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.

Discontinued Operations

During February 2011, we entered into an agreement to sell our Barnett Shale assets. Accordingly, in the first quarter 2011, we classified these assets and liabilities as discontinued operations in the accompanying consolidated balance sheets along with the historical results of the operations from such properties as discontinued operations, net of tax, in the accompanying statements of operations. See also Note 3 and Note 4 for more information regarding the sale of our Barnett Shale assets. Unless otherwise indicated, the information in these notes relate to our continuing operations.

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, natural gas liquids (“NGLs”) 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. This includes the reclassification of transportation and gathering revenue into other revenue. These reclassifications did not impact our net income from continuing operations, stockholders’ equity or cash flows.

Revision for Transportation, Gathering and Compression Expenses

As a result of our production growth and commencement of various transportation and gathering agreements in 2010 and 2011, we have revised our presentation of third party transportation and gathering costs to properly report such costs as a component of operating expenses in the accompanying statement of operations in accordance with Financial Accounting Standards Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. Previously, these costs were reflected as a component of natural gas, NGLs and oil sales. For more information on the accounting for these agreements, see Revenue Recognition, Gas Imbalances and Receivables below. We have concluded that this revision is not material to our financial statements and the net effect of these revisions did not impact our net income, stockholders’ equity or cash flows; however, previously reported natural gas, NGL and oil sales have increased and total operating expenses have increased by the same amount. The following reflects the revisions made (in thousands):


	2010		2009
Natural gas, NGL and oil sales, previously reported	$	760,453	$	714,564
Revision of transportation, gathering and compression expenses		62,837		37,185

Natural gas, NGL and oil sales, reported	$	823,290	$	751,749

The corresponding amounts have been reflected in transportation, gathering and compression expenses for 2010 and 2009 as shown below (in thousands):


	2010		2009
Transportation, gathering and compression expenses, previously reported	$	—	$	—
Revision of transportation, gathering and compression expenses		62,837		37,185

Transportation, gathering and compression, reported	$	62,837	$	37,185

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 we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, 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, Gas Imbalances and Receivables

Natural gas, NGL and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. As described in the revision section above, we are reporting our gathering and transportation costs in accordance with FASB Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we generally receive a net price from the purchaser (which is net of processing costs) which is also recorded in revenue at the net price we generally receive from the purchaser. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation expenses to a third party and receive proceeds from the purchaser with no transportation deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering and compression expense.

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 $4.0 million at December 31, 2011 compared to $5.0 million at December 31, 2010. During the year ended 2011, we recorded bad debt expense of $946,000 compared to $3.6 million in 2010 and $1.4 million in 2009.

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. At December 31, 2011, we had recorded a net liability of $50,000 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

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds are made up of investments which include equity securities 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 or repair operations. In 2011, we sold tubular goods and other inventory for proceeds of $8.0 million and recorded a gain of $359,000.

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 which is based upon the approximated relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. 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 an asset group, 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. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12.

Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization group are credited to the net book value of the 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 $748.6 million in 2011 compared to $648.1 million in 2010. Assets of discontinued operations include unproved properties of $163.7 million at December 31, 2010. We have recorded abandonment and impairment expense related to unproved properties from continuing operations of $79.7 million in 2011 compared to $49.7 million in 2010 and to $36.9 million in 2009.

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. Transportation and field assets also includes other property and equipment such as buildings, furniture and fixtures, leasehold improvements, data processing and communication equipment. These items are generally depreciated by individual components on a straight line basis over their economic useful life, which is generally from 3 to 15 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $16.2 million in 2011 compared to $16.1 million in 2010 and $31.6 million in 2009. 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, 2011 include $39.4 million of unamortized debt issuance costs, $50.2 million of marketable securities held in our deferred compensation plans and $14.4 million of other investments including land.

Accounts Payable

Included in accounts payable at December 31, 2011 and 2010, are liabilities of approximately $45.7 million and $97.2 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 (“Liability Awards”) and restricted stock unit awards (“Equity 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. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying statement of operations.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs 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 derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Through December 2011, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGLs 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 pre-tax gain of $11.6 million compared to a pre-tax gain of $5.4 million in 2009 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives. In 2011, we did not discontinue hedge accounting on any of our hedges.

We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas, NGLs and oil production. Accordingly, we record changes in the fair value of our hedge derivative 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 hedge derivative contracts are reclassified out of AOCI and into natural gas, NGLs 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. At times, we have also entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we may enter 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. We do not recognize a deferred tax asset for excess tax benefits that have not been realized.

Accumulated Other Comprehensive Income

The following details the components of AOCI and related tax effects for the three years ended December 31, 2011. Amounts included in AOCI relate to our derivative activity (in thousands).


	Gross			Tax Effect			Net of Tax
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
Contract settlements reclassified to income		(132,201	)		50,005			(82,196	)
Change in unrealized deferred hedging gains		275,817			(104,464	)		171,353

Accumulated other comprehensive income at December 31, 2011	$	254,678		$	(98,051	)	$	156,627

Accounting Pronouncements Implemented

Recently Adopted

In June 2011, the FASB issued Accounting Standards Update (“ASU”) No. 201-05, “Presentation of Comprehensive Income,” which was issued to enhance comparability between entities that report under U.S. GAAP and International Financial Reporting Standards (“IFRS”), and to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption of the new guidance is permitted and full retrospective application is required. We adopted this new requirement in third quarter 2011 and since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance will require prospective application. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.

Dispositions and Aquisitions

12 Months Ended

Dec. 31, 2011

Dispositions and Acquisitions [Abstract]

DISPOSITIONS AND ACQUISITIONS

(3) DISPOSITIONS AND ACQUISITIONS

2011 Dispositions

In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale properties located in North Central Texas (Dallas, Denton, Ellis, Hill, Hood, Johnson, Parker, Tarrant and Wise Counties), which also included the assumption of certain derivative contracts by the buyer and was subject to normal post-closing adjustments. We closed substantially all of this sale in April 2011 and closed the remainder in August 2011. The gross cash proceeds were approximately $889.3 million, including certain derivative contracts assumed by the buyer. The agreements had a February 1, 2011 effective date and consequently operating net revenues after February 2011 were a downward adjustment to the sales price. We recorded a pretax gain of $4.8 million in discontinued operations related to this sale. In the accompanying December 31, 2010 balance sheet, we have classified these assets and liabilities as discontinued operations. As indicated in Notes 2 and 4, the historic results of our Barnett Shale operations are presented as discontinued operations.

As part of the sale of our Barnett Shale properties, certain derivative contracts were assumed by the buyer. We received proceeds of $40.0 million for these derivative contracts and recorded a loss of $1.7 million in second quarter 2011, which is included in continuing operations. As required by cash flow hedge accounting rules, a $25.1 million pretax gain in AOCI related to these hedges was recognized in earnings during 2011 as the hedged production occurred. The hedges assumed by the buyer as part of the sale were not designated to our Barnett Shale production and were sold to balance our volumes hedged.

In fourth quarter 2011, we exchanged unproved property in Ohio for unproved property in Pennsylvania where we also received $11.5 million in cash as part of the transaction. We recorded a $4.5 million gain related to this transaction. In third quarter 2011, we sold various producing properties located in East Texas for proceeds of $10.5 million. We recognized an impairment charge of $31.2 million in third quarter 2011 related to these East Texas properties. For additional information on this impairment, see Note 12. Also in third quarter 2011, we sold producing properties in Pennsylvania for proceeds of $5.4 million, with no gain or loss recognized, as the sale did not materially impact the depletion rate of the remaining properties in the amortization base. In the first quarter 2011, we sold a low pressure pipeline for $14.7 million in proceeds, with no gain or loss recognized.

2010 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 remaining balance of $135.0 million was used to repay amounts outstanding under our credit facility.

2009 Dispositions

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.

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 2010 Dispositions above). No pro forma information has been provided as the acquisition was not considered significant.

Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations [Abstract]

DISCONTINUED OPERATIONS

(4) DISCONTINUED OPERATIONS

The following table represents the components of our Barnett Shale operations as discontinued operations for the years ended December 31, 2011, 2010 and 2009 (in thousands).


	Year Ended December 31,
	2011		2010			2009
Revenues and other income:
Natural gas, NGL and oil sales	$	59,185	$	157,778		$	139,357
Transportation and gathering		6		35			—
Gain on the sale of assets		4,771		955			—
Other		4		32			3

Total revenues and other income		63,966		158,800			139,360

Costs and expenses:
Direct operating		10,080		35,328			34,960
Transportation, gathering and compression		5,257		8,624			14,000
Production and ad valorem taxes		1,309		7,545			6,633
Exploration		37		581			2,209
Abandonment and impairment of unproved properties		—		20,233			76,603
Interest expense ^(a)		14,791		40,527			42,106
Depletion, depreciation and amortization		8,894		88,269			106,354
Impairment of proved properties		—		463,244			—

Total costs and expenses		40,368		664,351			282,865

Income (loss) before income taxes		23,598		(505,551	)		(143,505	)

Income tax expense (benefit)
Current		—		—			—
Deferred		8,278		(177,597	)		(50,655	)

		8,278		(177,597	)		(50,655	)

Net income (loss) from discontinued operations	$	15,320	$	(327,954	)	$	(92,850	)

^(a)	Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

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


	December 31,
	2011		2010
Composition of assets of discontinued operations:
Natural gas properties and oil properties, net	$	—	$	838,044
Transportation and field assets, net		—		684
Accounts receivable		—		30,575
Unrealized derivative gain		—		8,195
Inventory and other		—		81

Total current assets of discontinued operations	$	—	$	877,579

Composition of liabilities of discontinued operations:
Accounts payable	$	—	$	23,366
Accrued liabilities		653		10,871
Asset retirement obligations		—		—

Total current liabilities of discontinued operations	$	653	$	34,237

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

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

- Definition

The entire disclosure for the facts and circumstances leading to the completed or expected disposal, manner and timing of disposal, the gain (loss) recognized in the income statement and the income statement caption that includes that gain (loss), amounts of revenues and pretax profit or loss reported in discontinued operations, the segment in which the disposal group was reported, and the classification (whether sold or classified as held for sale) and carrying value of the assets and liabilities comprising the disposal group. Includes all disposal groups, including those classified as components of the entity (discontinued operations).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
-Paragraph 43-48
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
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-Section 50
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-Name Accounting Standards Codification
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+ Details

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

INCOME TAXES

(5) INCOME TAXES

Our income tax expense from continuing operations was $35.6 million for the year ended December 31, 2011 compared to $50.9 million in 2010 and $45.8 million in 2009. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2011			2010			2009
Federal statutory tax rate		35.0	%		35.0	%		35.0	%
State		7.0			(0.2	)		20.6
Non-deductible executive compensation		3.5			0.2			—
Valuation allowance		(0.4	)		1.4			(1.9	)
Other		0.3			0.1			0.3

Consolidated effective tax rate		45.4	%		36.5	%		54.0	%

Income tax provision attributable to income from continuing operations before income taxes consists of the following:


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Current:
U.S. federal	$	—	$	—		$	(1,000	)
U.S. state and local		637		(836	)		364

	$	637	$	(836	)	$	(636	)

Deferred:
U.S. federal	$	30,055	$	51,280		$	29,085
U.S. state and local		4,865		466			17,344

	$	34,920	$	51,746		$	46,429

Total income tax expense	$	35,557	$	50,910		$	45,793

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


	December 31,
	2011			2010
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	8,607		$	5,857
Current portion of asset retirement obligation		2,011			1,579
Other		1,423			4,106
Current portion of net operating loss carryforward		—			17,586

Total current		12,041			29,128

Non-current
Net operating loss carryforward		63,568			85,120
Deferred compensation		64,176			49,933
AMT credits and other credits		3,505			3,211
Non-current portion of asset retirement obligation		30,358			23,127
Cumulative unrealized mark-to-market loss		2,373			9,826
Other		22,076			23,481
Valuation allowance		(4,534	)		(4,841	)

Total non-current		181,522			189,857

Deferred tax liabilities:
Current
Net unrealized gain in AOCI related to hedge derivatives		(68,636	)		(40,976	)

Total current		(68,636	)		(40,976	)

Non-current
Depreciation, depletion and investments		(862,597	)		(858,502	)
Net unrealized gain in AOCI related to hedge derivatives		(29,415	)		(2,616	)
Other		—			(780	)

Total non-current		(892,012	)		(861,898	)

Net deferred tax liability	$	(767,085	)	$	(683,889	)

At December 31, 2011, deferred tax liabilities exceeded deferred tax assets by $767.1 million, with $98.1 million of deferred tax liability related to net deferred hedging gains included in AOCI. As of December 31, 2011, we have a $4.5 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to certain 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, 2010, we had a $4.8 million valuation allowance on the deferred tax asset related to our deferred compensation plan.

At December 31, 2011, we had regular net operating loss (“NOL”) carryforwards of $299.0 million and alternative minimum tax (“AMT”) NOL carryforwards of $261.3 million that expire between 2012 and 2031. We are expecting to generate approximately $50.0 million in federal taxable income in 2011 in order to utilize net operating loss carryforwards that expire in 2012. Our deferred tax asset related to regular NOL carryforwards at December 31, 2011 was $32.6 million, which is net of the Accounting Standards Codification 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, 2011, 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, 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 2007 and we are subject to various state tax examinations for years after 2006. We have not extended the statute of limitation period in any income tax jurisdiction. Our 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, 2011. Throughout 2011, our unrecognized tax benefits were not material.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Topic 740
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-Paragraph 9
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Income (Loss) Per Common Share

12 Months Ended

Dec. 31, 2011

Income (Loss) Per Common Share [Abstract]

INCOME (LOSS) PER COMMON SHARE

(6) INCOME (LOSS) PER COMMON SHARE

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


	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total			Continuing Operations		Discontinued Operations			Total
Income (loss) as reported	$	42,706		$	15,320		$	58,026		$	88,698		$	(327,954	)	$	(239,256	)	$	38,980	$	(92,850	)	$	(53,870	)
Participating basic earnings ^(a)		(763	)		(274	)		(1,037	)		(1,574	)		1,120			(454	)		—		—			—

Basic income (loss) attributed to common shareholders		41,943			15,046			56,989			87,124			(326,834	)		(239,710	)		38,980		(92,850	)		(53,870	)
Reallocation of participating earnings ^(a)		3			2			5			11			(11	)		—			—		—			—

Diluted income (loss) attributed to common shareholders	$	41,946		$	15,048		$	56,994		$	87,135		$	(326,845	)	$	(239,710	)	$	38,980	$	(92,850	)	$	(53,870	)

Income (loss) per common share:
Basic	$	0.26		$	0.10		$	0.36		$	0.56		$	(2.09	)	$	(1.53	)	$	0.25	$	(0.60	)	$	(0.35	)
Diluted	$	0.26		$	0.10		$	0.36		$	0.55		$	(2.07	)	$	(1.52	)	$	0.24	$	(0.58	)	$	(0.34	)

^(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. Participating securities, however, do not participate in undistributed net losses.

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):


	Year Ended December 31,
	2011		2010		2009
Denominator:
Weighted average common shares outstanding – basic		158,030		156,874		154,514
Effect of dilutive securities:
Director and employee stock options and SARs		1,411		1,554		4,264

Weighted average common shares outstanding – diluted		159,441		158,428		158,778

Weighted average common shares – basic excludes 2.9 million shares at December 31, 2011, 2.8 million shares at December 31, 2010 and 2.6 million shares at December 31, 2009 of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant). Stock appreciation rights (“SARs”) of 795,000, 2.1 million and 1.1 million shares for the years ended December 31, 2011, 2010 and 2009 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.

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2011

Suspended Exploratory Well Costs [Abstract]

SUSPENDED EXPLORATORY WELL COSTS

(7) 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 exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2011, 2010 and 2009 (in thousands except for number of projects):


	2011			2010			2009
Balance at beginning of period	$	23,908		$	19,052		$	47,623
Additions to capitalized exploratory well costs pending the determination of proved reserves		86,996			28,897			26,216
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(17,516	)		(24,041	)		(52,849	)
Capitalized exploratory well costs charged to expense		—			—			(1,938	)

Balance at end of period		93,388			23,908			19,052
Less exploratory well costs that have been capitalized for a period of one year or less		(83,860	)		(13,181	)		(10,778	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	9,528		$	10,727		$	8,274

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

As of December 31, 2011, the $9.5 million of capitalized exploratory well costs that have been capitalized for more than one year relates primarily to wells waiting on pipelines, with all three 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, 2011 (in thousands):


	Total		2011		2010		2009		2008
Capitalized exploratory well costs that have been capitalized for more than one year	$	9,528	$	414	$	4,707	$	2,884	$	1,523

Indebtedness

12 Months Ended

Dec. 31, 2011

Indebtedness [Abstract]

INDEBTEDNESS

(8) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2011 is shown parenthetically) (in thousands). No interest was capitalized during 2011, 2010, and 2009:


	December 31,
	2011		2010
Bank debt (2.2%)	$	187,000	$	274,000

Senior subordinated notes:
6.375% senior subordinated notes due 2015		—		150,000
7.5% senior subordinated notes due 2016, net of $317 discount		—		249,683
7.5% senior subordinated notes due 2017		250,000		250,000
7.25% senior subordinated notes due 2018		250,000		250,000
8.0% senior subordinated notes due 2019, net of $12,033 and $13,147 discount, respectively		287,967		286,853
6.75% senior subordinated notes due 2020		500,000		500,000
5.75% senior subordinated notes due 2021		500,000		—

Total debt	$	1,974,967	$	1,960,536

Bank Debt

In February 2011, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On December 31, 2011, the facility amount was $1.5 billion and the borrowing base was $2.0 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 financial institutions, 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 December 31, 2011, the outstanding balance under the bank credit facility was $187.0 million as well as $28.6 million of undrawn letters of credit leaving $1.3 billion of borrowing capacity available under the facility amount. The facility 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 1.5% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.5% 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, 2011 compared to 2.2% for the year ended December 31, 2010 and 2.4% for the year ended December 31, 2009. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2011, the commitment fee was 0.375% and the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.

Senior Subordinated Notes

In May 2011, we issued $500.0 million aggregate principal amount of 5.75% senior subordinated notes due 2021 (“5.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 5.75% Notes were issued at par. Interest on the 5.75% Notes is payable semi-annually in June and December and is guaranteed by all of our current subsidiaries. We may redeem the 5.75% Notes, in whole or in part, at any time on or after June 1, 2016, at redemption prices of 102.875% of the principal amount as of June 1, 2016, declining to 100.0% on June 1, 2019 and thereafter. Before June 2014, we may redeem up to 35% of the original aggregate principal amount of the 5.75% Notes at a redemption price equal to 105.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of 5.75% Notes remains outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. On closing, we used $112.9 million of the proceeds to purchase our 6.375% senior subordinated notes due 2015 and $207.1 million of the proceeds to purchase our 7.5% senior subordinated notes due 2016 as part of the tender offer and redemption described below.

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

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 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at December 31, 2011.

The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At December 31, 2011, we were in compliance with these covenants.

Following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2011 (in thousands):


	Year Ended December 31,
2012	$	—
2013		—
2014		—
2015		—
2016		187,000
2017		250,000
Thereafter		1,537,967

	$	1,974,967

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

(9) 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, 2011 and 2010 is as follows (in thousands):


	2011			2010
Beginning of period – continuing operations	$	60,693		$	76,589
Liabilities incurred		3,265			1,495
Acquisitions-continuing operations		—			556
Liabilities settled		(4,717	)		(2,331	)
Disposition of wells		(716	)		(12,891	)
Accretion expense-continuing operations		5,488			5,137
Change in estimate		20,797			(7,862	)

End of period – continuing operations		84,810			60,693

Less current portion		(5,005	)		(4,020	)

Long-term asset retirement obligations – continuing operations	$	79,805		$	56,673

Asset retirement obligations-discontinued operations	$	—		$	1,980

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, 2011

Capital Stock [Abstract]

CAPITAL STOCK

(10) 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 2009:


	Year Ended December 31,
	2011		2010		2009
Beginning balance		159,909,052		158,118,937		155,375,487
Shares issued in lieu of cash bonuses		—		—		184,926
Stock options/SARs exercised		862,774		991,988		1,384,861
Restricted stock grants		326,591		405,127		413,353
Issued for acreage purchases		—		380,229		743,737
Treasury shares		33,130		12,771		16,573

Ending balance		161,131,547		159,909,052		158,118,937

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, 2011, 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, 2011, we have $156.4 million remaining under this acquisition and business combination 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 2011, 2010 and 2009. 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.

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 4
-Section 08
-Paragraph d

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Chapter 1
-Section B
-Paragraph 7, 11A
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
-Paragraph 2, 3, 4, 5, 6, 7, 8
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Section 08
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 29, 30, 31
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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Reference 21: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6521494

Reference 22: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Derivative Activities

12 Months Ended

Dec. 31, 2011

Derivative Activities [Abstract]

DERIVATIVE ACTIVITIES

(11) 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 as we typically utilize commodity swap, collar or call option contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. In 2011, we entered into NGL derivative swap contracts for the natural gasoline (or C5) component of natural gas liquids. In 2010, we 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, 2011, we had open swap contracts covering 66.8 Bcf of natural gas at prices averaging $4.06 per mcf, 1.8 million barrels of oil at prices averaging $94.43 per barrel and 6.6 million barrels of NGLs (the C5 component of NGLs) at prices averaging $93.30 per barrel. At December 31, 2011, we had collars covering 206.4 Bcf of gas at weighted average floor and cap prices of $4.76 to $5.27 per mcf and 2.6 million barrels of oil at weighted average floor and cap prices of $83.26 to $94.28 per barrel. At December 31, 2011, we also had sold call options for 1.7 million barrels of oil at a weighted average price of $85.00 per barrel. 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 $251.3 million at December 31, 2011. These contracts expire monthly through December 2014. The following table sets forth the derivative volumes by year as of December 31, 2011.


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2012	Collars	234,887 Mmbtu/day	$ 4.99–$ 5.50
2013	Collars	240,000 Mmbtu/day	$ 4.73–$ 5.20
2014	Collars	90,000 Mmbtu/day	$ 4.25–$ 4.85
2012	Swaps	182,986 Mmbtu/day	$4.06

Crude Oil
2012	Collars	2,000 bbls/day	$ 70.00–$ 80.00
2013	Collars	3,000 bbls/day	$ 90.60–$ 100.00
2014	Collars	2,000 bbls/day	$ 85.55–$ 100.00
2012	Call options	4,700 bbls/day	$85.00
2013	Swaps	3,000 bbls/day	$95.55
2014	Swaps	2,000 bbls/day	$92.75

NGLs (Natural Gasoline)
2012	Swaps	12,000 bbls/day	$96.28
2013	Swaps	6,000 bbls/day	$87.33

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, NGLs and oil sales when the underlying physical transaction occurs and the hedging contract is settled. As of December 31, 2011, an unrealized pre-tax derivative gain of $254.7 million was recorded in AOCI. This gain will be reclassified into earnings as a gain of $177.6 million in 2012, a gain of $73.5 million in 2013 and a gain of $3.5 million in 2014 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, NGLs and oil sales in the period the hedged production is sold. Natural gas, NGLs and oil sales include $123.6 million of gains in 2011 compared to gains of $64.8 million in 2010 and gains of $202.9 million in 2009 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 changes 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, 2011 includes ineffective gains (unrealized and realized) of $9.5 million compared to $2.0 million in 2010 and $3.1 million in 2009.

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, 2011 (in thousands):


	2011			2010			2009
Change in fair value of derivatives that do not qualify for hedge accounting ^(a)	$	15,762		$	(2,086	)	$	(115,909	)
Realized gain (loss) on settlement–natural gas ^(a) ^(b)		14,743			35,988			171,998
Realized gain (loss) on settlement–oil ^{(a) (b)}		(9,574	)		—			7,304
Realized gain (loss) on settlement–NGL ^{(a) (b)}		9,612			—			—
Realized gain on early settlement of oil derivatives		—			15,697			—
Hedge ineffectiveness–realized		7,361			(352	)		4,749
–unrealized		2,183			2,387			(1,696	)

Derivative fair value income	$	40,087		$	51,634		$	66,446

^(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.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2011 and 2010 is summarized below (in thousands). As of December 31, 2011, we are conducting derivative activities with eleven financial institutions, of which all but two 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 and we have master netting arrangements.


	December 31,
	2011			2010
Derivative assets:
Natural gas–swaps	$	54,162		$	—
–collars		228,228			155,159
–collars – discontinued operations		—			8,195
Crude oil–swaps		(263	)		—
–collars		(16,607	)		—
–call options		(29,348	)		(31,904	)
NGL–swaps		15,328			—

	$	251,500		$	131,450

Derivative liabilities:
Natural gas–collars	$	—		$	27,032
–basis swaps		—			(352	)
Crude oil–collars		—			(12,051	)
–call options		—			(28,393	)
NGL–swaps		(173	)		—

	$	(173	)	$	(13,764	)

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


	December 31, 2011								December 31, 2010
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying Value		Carrying Value			Net Carrying Value			Carrying Value		Carrying Value			Net Carrying Value
Derivatives that qualify for cash flow hedge accounting :
Swaps ^(a)	$	54,318	$	(419	)	$	53,899		$	—	$	—		$	—
Collars ^(a)		228,228		(1,954	)		226,274			164,933		—			164,933
Collars – discontinued Operations ^(b)		—		—			—			8,195		—			8,195

	$	282,546	$	(2,373	)	$	280,173		$	173,128	$	—		$	173,128

Derivatives that do not qualify for hedge accounting :
Swaps ^(a)	$	17,949	$	(2,794	)	$	15,155		$	—	$	—		$	—
Collars ^(a)		—		(14,653	)		(14,653	)		17,259		(12,052	)		5,207
Call options ^(a)		—		(29,348	)		(29,348	)		—		(60,297	)		(60,297	)
Basis swaps ^(a)		—		—			—			—		(352	)		(352	)

	$	17,949	$	(46,795	)	$	(28,846	)	$	17,259	$	(72,701	)	$	(55,442	)

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

^(b)	Included in assets of discontinued operations.

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 is summarized below:


	Year Ended December 31,
	Change in Hedge Derivative Fair Value						Realized Gain Reclassified from OCI into Revenue ^(a)
	2011			2010			2011			2010
Swaps	$	51,997		$	—		$	—		$	—
Collars		223,408			157,447			123,594			64,772
Collars – discontinued operations		412			8,195			8,607			—
Income taxes		(104,464	)		(64,662	)		(50,005	)		(24,841	)

	$	171,353		$	100,980		$	82,196		$	39,931

^(a)	For realized gains upon contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGLs and oil sales. For realized losses upon contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGLs 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 statements of operations is summarized below:


	Year Ended December 31,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)									Gain (Loss) Recognized in Income (Ineffective Portion)						Derivative Fair Value Income
	2011			2010			2009			2011		2010		2009		2011			2010			2009
Swaps	$	24,767		$	—		$	63,755		$	—	$	—	$	—	$	24,767		$	—		$	63,755
Collars		5,266			65,996			33,859			9,544		2,035		3,053		14,810			68,031			36,912
Call options		553			(15,895	)		—			—		—		—		553			(15,895	)		—
Basis swaps		(43	)		(502	)		(34,221	)		—		—		—		(43	)		(502	)		(34,221	)

Total	$	30,543		$	49,599		$	63,393		$	9,544	$	2,035	$	3,053	$	40,087		$	51,634		$	66,446

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

(12) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows.

•

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

•

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

•

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

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Fair Values-Recurring

We use a market approach for our 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, 2011 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2011
Trading securities held in the deferred compensation plans	$	50,237	$	—		$	—	$	50,237
Derivatives–swaps		—		69,054			—		69,054
–collars		—		211,621			—		211,621
–call options		—		(29,348	)		—		(29,348	)


	Fair Value Measurements at December 31, 2010 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2010
Trading securities held in the deferred compensation plans	$	47,794	$	—		$	—	$	47,794
Derivatives–collars		—		170,140			—		170,140
–collars – discontinued operations		—		8,195			—		8,195
–call options		—		(60,297	)		—		(60,297	)
–basis swaps		—		(352	)		—		(352	)

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2011 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in 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, 2011, interest and dividends were $1.4 million and mark-to-market was a loss of $2.3 million. For the year ended December 31, 2010, interest and dividends were $864,000 and the 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.

Fair Values-Non recurring

We review our long-lived assets for impairment, including proved natural gas and oil properties, whenever events or circumstances indicate the carrying value of those assets may not be recoverable. During the year ended December 31, 2011, we recognized charges for impairment of oil and gas properties in continuing operations of $38.7 million compared to $6.5 million in 2010 and $930,000 in 2009. Discontinued operations includes an impairment charge related to our Barnett Shale assets of $463.2 million in 2010.

Continuing Operations

Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying values of our oil and gas properties in East Texas, onshore Gulf Coast and Michigan may be impaired and undiscounted cash future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value 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. In the case of certain of our East Texas properties, we also considered the potential sale of certain of these properties. We recorded non-cash charges during 2011 of $31.2 million related to our East Texas natural gas and oil properties and $7.5 million related to our Gulf Coast onshore properties. 2010 includes impairment charges of $6.5 million related to our Gulf Coast onshore properties and 2009 includes an impairment charge of $930,000 related to our Michigan 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,
	2011				2010				2009
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties – continuing operations	$	24,388	$	38,681	$	16,075	$	6,505	$	1,244	$	930
Natural gas and oil properties – discontinued operations		—		—		835,913		463,244		—		—
Equity investments		—		—		—		—		2,895		8,950

Discontinued Operations

Our Barnett properties did not meet held for sale criteria as of December 31, 2010 but our analysis reflected undiscounted cash flows for these properties were less than their carrying value. We 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, which is reflected in discontinued operations. 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.

Fair Values – Reported

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


	December 31, 2011						December 31, 2010
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and call options	$	251,500		$	251,500		$	123,255		$	123,255
Commodity collars – discontinued operations		—			—			8,195			8,195
Marketable securities^(a)		50,237			50,237			47,794			47,794
Liabilities:
Commodity swaps, collars, call options and basis swaps		(173	)		(173	)		(13,764	)		(13,764	)
Bank credit facility^(b)		(187,000	)		(187,000	)		(274,000	)		(274,000	)
6.375% senior subordinated notes due 2015^(b)		—			—			(150,000	)		(153,000	)
7.5% senior subordinated notes due 2016^(b)		—			—			(249,683	)		(259,375	)
7.5% senior subordinated notes due 2017^(b)		(250,000	)		(265,625	)		(250,000	)		(263,438	)
7.25% senior subordinated notes due 2018^(b)		(250,000	)		(267,500	)		(250,000	)		(263,750	)
8.0% senior subordinated notes due 2019^(b)		(287,967	)		(334,500	)		(286,853	)		(326,625	)
6.75% senior subordinated notes due 2020^(b)		(500,000	)		(555,000	)		(500,000	)		(515,625	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(541,250	)		—			—

^(a)	Marketable securities are held in our deferred compensation plans that are actively traded on major exchanges.

^(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.

Concentrations of Credit Risk

As of December 31, 2011, our primary concentrations of credit risk 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 $4.0 million at December 31, 2011 compared to $5.0 million at December 31, 2010. As of December 31, 2011, our derivative contracts consist of swaps, collars and call options. Our exposure is diversified primarily among major investment grade financial institutions, the majority of which we have master netting agreements which provides for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and or credit ratings. We may also limit the level of exposure with any single counterparty. At December 31, 2011 our derivative counterparties include eleven financial institutions, of which all but two are secured lenders in our bank credit facility. At December 31, 2011, our net derivative asset includes a receivable from two counterparties not included in our bank credit facility of $9.6 million. For those counterparties that are not secured lenders in our bank credit facility or for which we do not have master netting arrangements, net derivative asset values are determined in part, by reviewing credit default swap spreads for the counterparties. Net derivative liabilities are determined, in part, by using our market based credit spread. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date. We have also entered into the International SWAP Dealers Association Master Agreements (“ISDA Agreements”) with our counterparties. The terms of the ISDA Agreements provide us and our counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2011

Stock-Based Compensation Plans [Abstract]

STOCK-BASED COMPENSATION PLANS

(13) 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 Director Plan.

Stock-Based Awards

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 expired 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. Beginning in first quarter 2011, the compensation committee also began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us.

The Compensation Committee also 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. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the shares are placed in our deferred compensation plan and, upon vesting, employees are allowed to take withdrawals either in cash or in stock. These Liability Awards are classified as a liability 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 authorized but unissued shares of stock when restricted stock is granted. 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 2011, stock-based compensation was allocated to operating expense ($2.0 million), exploration expense ($4.1 million), general and administrative expense ($36.2 million) for a total of $43.8 million. In 2010, stock-based compensation was allocated to operating expense ($2.0 million), exploration expense ($4.2 million), general and administrative expense ($34.2 million) and termination costs ($2.8 million) for a total of $44.4 million. In 2009, stock-based compensation was allocated to operating expense ($2.5 million), exploration expense ($4.7 million) general administrative expense ($33.3 million) and termination costs ($332,000) for a total of $41.6 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, 2011, cash received upon exercise of stock options/SARs awards was $620,000. For the twelve months ended December 31, 2010 and 2009, tax benefits realized for deductions that were in excess of the stock-based compensation expense were not recognized due to our net operating loss position. In 2011, as a result of realizing federal taxable income, a tax benefit of $11.7 million has been recognized in our net operating loss carryforward for the excess tax deduction over our stock-based compensation expense.

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 units 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. Of the 4.6 million grants outstanding at December 31, 2011, 635,000 of the grants relate to stock options with the remainder of 3.9 million grants relating to SARs. Information with respect to stock option and SARs activities is summarized below.


	Shares			Weighted Average Exercise Price
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
Granted		843,485			51.17
Exercised		(2,511,989	)		32.69
Expired/forfeited		(234,726	)		52.65

Outstanding at December 31, 2011		4,558,609		$	41.47

The following table shows information with respect to stock options and SARs outstanding and exercisable at December 31, 2011:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$1.29 – $ 9.99		619,716		0.29	$	3.41		619,716	$	3.41
10.00 – 19.99		15,435		3.73		19.63		15,435		19.63
20.00 – 29.99		—		—		—		—		—
30.00 – 39.99		808,975		1.52		34.90		506,868		35.30
40.00 – 49.99		1,968,934		3.12		45.28		643,665		43.63
50.00 – 59.99		803,137		3.29		54.39		310,905		57.64
60.00 – 69.99		13,542		1.65		66.04		12,677		65.91
70.00 – 75.00		328,870		1.39		75.00		328,870		75.00

Total		4,558,609		2.35	$	41.47		2,438,136	$	37.66

Stock Appreciation Right Awards

During 2011, 2010 and 2009, 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:


	2011			2010			2009
Weighted average exercise price per share	$	51.17		$	46.09		$	36.90
Expected annual dividends per share		0.31	%		0.35	%		0.44	%
Expected life in years		3.7			3.6			3.5
Expected volatility		47	%		49	%		58	%
Risk-free interest rate		1.4	%		1.6	%		1.5	%
Weighted average grant date fair value	$	18.22		$	17.01		$	15.42

The dividend yield is based on the current annual dividend at the time of grant. The expected life was based on the historical exercise activity. The expected 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, 2011 was $62.5 million compared to $50.6 million in 2010 and $50.9 million in 2009. As of December 31, 2011, the aggregate intrinsic value of the awards outstanding was $97.7 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option/SARs awards currently exercisable was $63.6 million and 1.5 years. As of December 31, 2011, the number of fully vested awards and awards expected to vest was 4.4 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $41.32 and 2.3 years and the aggregate intrinsic value was $94.7 million. As of December 31, 2011, unrecognized compensation cost related to the awards was $20.2 million, which is expected to be recognized over a weighted average period of 1.7 years.

Restricted Stock Awards

Equity Awards

In 2011, we granted 331,000 restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded compensation expense for these awards of $4.2 million in the year ended December 31, 2011. As of December 31, 2011, there was $11.0 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 2.2 years. Equity Awards are not issued to employees until such time they are vested and the employees do not have the option to receive cash.

Liability Awards

In 2011, we granted 350,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $51.17. This grant included 16,000 issued to non-employee directors which vest immediately and 334,000 to employees with vesting generally over a three-year period. In 2010, we granted 413,000 shares of Liability Awards as compensation to directors and employees at an average price of $45.83. This grant included 21,000 issued to non-employee 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 Liability Awards as compensation to directors and employees at an average price of $39.99. This grant included 23,000 issued to non-employee directors, which vest immediately and 663,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $19.1 million in the year ended December 31, 2011 compared to $20.5 million in 2010 and $19.7 million in 2009. As of December 31, 2011, there was $21.0 million of unrecognized compensation related to Liability Awards expected to be recognized over a weighted average period of 1.7 years. Substantially all of these awards are held in our deferred compensation plan, are classified as liability 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 $12.9 million in 2011.

A summary of the status of our non-vested restricted stock outstanding at December 31, 2011 is summarized below:


	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2008		—		$	—		473,547		$	48.50
Granted		—			—		685,578			39.99
Vested		—			—		(521,536	)		40.91
Forfeited		—			—		(10,400	)		40.83

Outstanding at December 31, 2009		—			—		627,189			45.64
Granted		—			—		413,422			45.83
Vested		—			—		(439,361	)		46.90
Forfeited		—			—		(18,499	)		46.04

Outstanding at December 31, 2010		—			—		582,751			44.81
Granted		331,209			49.56		349,840			51.17
Vested		(88,854	)		49.37		(416,055	)		45.50
Forfeited		(20,746	)		49.45		(29,292	)		45.04

Outstanding at December 31, 2011		221,609		$	49.64		487,244		$	48.76

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 2011, we contributed $3.3 million to the 401(k) Plan compared to $3.1 million in 2010. 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 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 loss of $43.2 million in 2011 compared to mark-to-market income of $10.2 million in 2010 and mark-to-market loss of $31.1 million in 2009. The Rabbi Trust held 2.8 million shares (2.3 million of vested shares) of Range stock at December 31, 2011 compared to 2.9 million shares (2.3 million of vested shares) at December 31, 2010.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

(14) SUPPLEMENTAL CASH FLOW INFORMATION


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Net cash provided from operating activities included:
Income taxes paid (refunded from) to taxing authorities	$	675	$	(1,359	)	$	170
Interest paid		133,103		116,766			108,685

Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net		24,061		(6,370	)		4,985
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, 2011

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

(15) 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 and amounts related to discontinued operations) totaled $18.6 million in 2011 compared to $18.5 million in 2010 and $18.8 million in 2009. 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
2012	$	12,843
2013		11,648
2014		10,923
2015		10,755
2016		8,438
Thereafter		27,701
Sublease rentals		(963	)

	$	81,345

Transportation and Gathering Contracts

We have entered firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production primarily from our properties in Pennsylvania. Under these contracts, we are obligated to transport or gather 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, 2011, future minimum transportation and gathering fees under our commitments are as follows (in thousands):


	Transportation and Gathering Contracts
2012	$	103,030
2013		102,693
2014		102,221
2015		99,298
2016		99,424
Thereafter		506,798

	$	1,013,464

In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2028 to deliver natural gas and ethane production volumes in Appalachia from certain Marcellus Shale wells. These agreements, which are contingent on certain pipeline modifications, are for 143,000 mcfe per day in 2012, 251,900 mcfe per day in 2013, 346,400 mcfe per day in 2014, 363,000 mcfe per day in 2015, 438,800 mcfe per day in 2016 and 443,000 mcfe per day until the end of the contractual term.

Drilling Contracts

As of December 31, 2011, we have contracts with drilling contractors to use three drilling rigs with terms of up to three years and minimum future commitments of $25.0 million in 2012, $14.7 million in 2013 and $896,000 in 2014. Early termination of these contracts at December 31, 2011 would have required us to pay maximum penalties of $22.2 million. We do not expect to pay any early termination penalties related to these contracts.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Midcontinent and Marcellus areas. We may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2011, our delivery commitments through 2028 were as follows:


Year Ending December 31,	Natural Gas and Ethane (mcfe per day)
2012		1,370
2013		33,434
2014		96,174
2015		98,913
2016		99,589
Thereafter		90,000

Other

We have agreements in place for hydraulic fracturing including related equipment, material and labor for $70.1 million in 2012 and $52.6 million in 2013. We also have agreements to purchase seismic data for $7.2 million in 2012 and $1.8 million in 2013. 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 a significant component of our cost structure and is 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.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Number 5
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Major Customers

12 Months Ended

Dec. 31, 2011

Major Customers [Abstract]

MAJOR CUSTOMERS

(16) 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 typically sold to natural gas processors or, in some cases, to other purchasers or users of NGLs. For the year ended December 31, 2011, we had two customers that accounted for 10% or more of total natural gas, NGLs and oil sales. For the year ended December 31, 2010, we had no customers that accounted for 10% or more of total natural gas, NGLs and oil sales. For the year ended December 31, 2009, we had no customers that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our Natural gas, NGLs and oil production.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Equity Method Investments

12 Months Ended

Dec. 31, 2011

Equity Method Investments [Abstract]

EQUITY METHOD INVESTMENTS

(17) 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 2011, 2010 and 2009. During the year ended December 31, 2009, we received $301,000 in cash distributions from Whipstock. 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, 2011, our equity in the losses of Whipstock totaled $487,000 compared to losses of $2.2 million in 2010 and losses of $13.1 million in 2009. In 2011, equity in the losses of Whipstock was reduced by $6,000 to eliminate the profit on services provided to us compared to $1.1 million in 2010 and $422,000 in 2009. 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 $1.1 million at December 31, 2011. 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. In 2011 or 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 2011, 2010 and 2009. There were no dividends or partnership distributions received from NGLLC during the years ended December 31, 2010 or December 31, 2009. In 2011, we received partnership distributions of $23.5 million. 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, 2011, our equity in the losses of NGLLC of $563,000 reflects a reduction of $7.7 million to eliminate the profit on the gathering and transportation fees charged to us. For the year ended December 31, 2010, our equity in the income of NGLLC of $684,000 reflects a reduction of $8.8 million to eliminate the profit on gathering and transportation fees charged to us. For the year ended December 31, 2009, our equity in the earnings of NGLLC of $629,600 reflects a reduction of $7.0 million to eliminate the profit on gathering and transportation fees charged to us. Our net book value in this equity investment was $137.0 million at December 31, 2011.

- Definition

The entire disclosure for equity investment, or group of investments, for which combined disclosure is appropriate, including: (a) the name of each investee and percentage of ownership of common stock, (b) accounting policies for investments in common stock, (c) difference between the amount at which the investment is carried and the amount of underlying equity in net assets and the accounting treatment of the difference, (d) the total fair value of each identified investment for which a market value is available, (e) summarized information as to assets, liabilities, and results of operations of the investees (for investments in unconsolidated subsidiaries, common stock of joint ventures, or other investments using the equity method), and (f) material effects of possible conversions, exercises, or contingent issuances of the investee. Other disclosures include (a) the names of any investee in which the investor owns 20 percent or more of the voting stock and investment is not accounted for using the equity method, and the reasons why not, and (b) the names of any investee in which the investor owns less than 20 percent of the voting stock and the investment is accounted for using the equity method, and the reasons why it is.

+ References + Details

Office Closing and Exit Activities

12 Months Ended

Dec. 31, 2011

Office Closing and Exit Activities [Abstract]

OFFICE CLOSING AND EXIT ACTIVITIES

(18) OFFICE CLOSING AND EXIT ACTIVITIES

In February 2010, we entered into an agreement to sell our natural gas and oil 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):


	2011			2010			2009
Beginning balance	$	1,092		$	1,568		$	—
Accrued one-time termination costs		—			5,138			1,895
Office lease		—			514			252
Payments		(1,040	)		(6,128	)		(579	)

Ending balance	$	52		$	1,092		$	1,568

- Definition

The entire disclosure for restructuring and related activities. Description of restructuring activities such as exit and disposal activities, include facts and circumstances leading to the plan, the expected plan completion date, the major types of costs associated with the plan activities, total expected costs, the accrual balance at the end of the period, and the periods over which the remaining accrual will be settled.

+ References + Details

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Data [Abstract]

SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

(19) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. We have revised prior period natural gas, NGLs and oil sales and costs and total expenses as discussed in Note 2. Natural gas, NGLs and oil sales were increased by $25.1 million in the first quarter of 2011, $28.7 million in the second quarter of 2011 and $32.4 million in the third quarter of 2011. Natural gas, NGLs and oil sales were increased by $13.0 million in the first quarter of 2010, $14.4 million in the second quarter of 2010, $15.5 million in the third quarter of 2010 and $20.0 million in the fourth quarter of 2010. Income (loss) from continuing operations did not change because the offsetting amounts are included in transportation, gathering and compression expense (in thousands). Abandonment and impairment of unproved properties in the fourth quarter 2011 includes $3.0 million related to prior years. In addition, 2011 deferred tax expense in fourth quarter includes $3.1 million related to prior years.


	2011
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	251,963		$	285,353		$	304,230		$	331,720		$	1,173,266
Derivative fair value (loss) income		(40,834	)		53,039			65,761			(37,879	)		40,087
Gain (loss) on the sale of assets		139			(1,622	)		203			3,540			2,260
Other		1,390			(1,475	)		442			2,686			3,043

Total revenue and other income		212,658			335,295			370,636			300,067			1,218,656

Costs and expenses:
Direct operating		28,717			28,509			29,828			25,918			112,972
Transportation, gathering and compression		25,082			28,666			32,431			34,576			120,755
Production and ad valorem taxes		6,879			7,550			7,317			5,920			27,666
Exploration		27,187			11,592			17,606			24,982			81,367
Abandonment and impairment of unproved properties		16,537			18,900			16,627			27,639			79,703
General and administrative		33,959			39,120			35,907			42,205			151,191
Deferred compensation plan		30,630			(5,778	)		8,717			9,640			43,209
Interest expense		24,779			31,383			34,181			34,709			125,052
Loss on early extinguishment of debt		—			18,580			(4	)		—			18,576
Depletion, depreciation and amortization		72,216			78,294			93,619			97,092			341,221
Impairment of proved properties		—			—			38,681			—			38,681

Total costs and expenses		265,986			256,816			314,910			302,681			1,140,393

(Loss) income from continuing operations before income taxes		(53,328	)		78,479			55,726			(2,614	)		78,263

Income tax (benefit) expense
Current		—			8			(7	)		636			637
Deferred		(19,897	)		32,695			22,547			(425	)		34,920

		(19,897	)		32,703			22,540			211			35,557

(Loss) income from continuing operations		(33,431	)		45,776			33,186			(2,825	)		42,706
Discontinued operations, net of taxes		8,398			5,517			1,569			(164	)		15,320

Net (loss) income	$	(25,033	)	$	51,293		$	34,755		$	(2,989	)	$	58,026

(Loss) income per common share:
Basic-(loss) income from continuing operations	$	(0.21	)	$	0.28		$	0.21		$	(0.02	)	$	0.26
-discontinued operations		0.05			0.04			0.01			—			0.10

-net (loss) income	$	(0.16	)	$	0.32		$	0.22		$	(0.02	)	$	0.36

Diluted-(loss) income from continuing operations	$	(0.21	)	$	0.28		$	0.20		$	(0.02	)	$	0.26
-discontinued operations		0.05			0.04			0.01			—			0.10

-net (loss) income	$	(0.16	)	$	0.32		$	0.21		$	(0.02	)	$	0.36


	2010
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	200,633		$	187,523		$	203,255		$	231,879		$	823,290
Derivative fair value income (loss)		42,333			6,546			9,981			(7,226	)		51,634
Gain (loss) on the sale of assets		67,913			10,176			67			(1,514	)		76,642
Other		506			1,300			(2,650	)		914			70

Total revenue and other income		311,385			205,545			210,653			224,053			951,636

Costs and expenses:
Direct operating		21,836			21,171			25,535			27,732			96,274
Transportation, gathering and compression		12,960			14,370			15,498			20,009			62,837
Production and ad valorem taxes		6,542			5,663			6,903			6,999			26,107
Exploration		14,139			14,420			15,225			16,722			60,506
Abandonment and impairment of unproved properties		6,551			9,727			14,435			19,025			49,738
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		20,931			21,271			23,363			25,100			90,665
Loss on early extinguishment of debt		—			—			5,351			—			5,351
Depletion, depreciation and amortization		64,807			67,813			69,730			72,888			275,238
Impairment of proved properties		6,505			—			—			—			6,505

Total costs and expenses		184,667			176,136			207,216			244,009			812,028

Income (loss) from continuing operations before income taxes		126,718			29,409			3,437			(19,956	)		139,608

Income tax expense (benefit)
Current		—			—			(10	)		(826	)		(836	)
Deferred		49,012			11,763			794			(9,823	)		51,746

		49,012			11,763			784			(10,649	)		50,910

Income (loss) from continuing operations		77,706			17,646			2,653			(9,307	)		88,698
Discontinued operations, net of taxes		(127	)		(8,594	)		(10,821	)		(308,412	)		(327,954	)

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

Income (loss) per common share:
Basic-income (loss) from continuing operations	$	0.49		$	0.11		$	0.02		$	(0.06	)	$	0.56
-discontinued operations		—			(0.05	)		(0.07	)		(1.96	)		(2.09	)

-net income (loss)	$	0.49		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.53	)

Diluted-income (loss) from continuing operations	$	0.48		$	0.11		$	0.02		$	(0.06	)	$	0.55
-discontinued operations		—			(0.05	)		(0.07	)		(1.96	)		(2.07	)

-net income (loss)	$	0.48		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.52	)

Principal Unconsolidated Investees (unaudited)


Company	December 31, 2011 Ownership	Activity
Whipstock Natural Gas Services, LLC	50%	Drilling services
Nora Gathering, LLC	50%	Gas gathering and transportation

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

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

12 Months Ended

Dec. 31, 2011

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 (UNAUDITED)

(20) 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,
	2011			2010			2009
				(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	6,035,429		$	4,742,248		$	4,144,007
Unproved properties		748,598			648,143			572,471

Total		6,784,027			5,390,391			4,716,478
Accumulated depreciation, depletion and amortization		(1,626,461	)		(1,306,378	)		(1,164,843	)

Net capitalized costs	$	5,157,566		$	4,084,013		$	3,551,635

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

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


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Acquisitions:
Unproved leasehold	$	—	$	3,697		$	—
Proved oil and gas properties		—		130,767			—
Asset retirement obligations		—		556			—
Acreage purchases ^(b)		220,576		151,572			162,172
Development		1,007,049		727,720			374,970
Exploration:
Drilling		226,920		50,433			49,029
Expense		77,259		56,298			39,873
Stock-based compensation expense		4,108		4,209			4,817
Gas gathering facilities:
Development		53,387		19,627			27,937

Subtotal		1,589,299		1,144,879			658,798
Asset retirement obligations		24,061		(6,370	)		4,985

Total – continuing operations		1,613,360		1,138,509			663,783
Discontinued operations		3,241		73,369			150,461

Total costs incurred	$	1,616,601	$	1,211,878		$	814,244

^(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.

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reserves of natural gas, natural gas liquids, crude oil and condensate are estimated by our petroleum engineering staff 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 2011, 2010 and 2009.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2011, the following independent petroleum consultants conducted an audit of our reserves: DeGolyer and MacNaughton (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, 2011, these consultants collectively audited approximately 89% of our proved reserves. Copies of the summary reserve reports prepared by each of these independent petroleum consultants are 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 audit 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 and Economics. 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%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, 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.

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, 2011 to estimate reserve information were $85.59 per barrel of oil, $49.24 per barrel for natural gas liquids and $3.55 per mcf for gas, using benchmark (NYMEX) of $95.61 per barrel and $4.12 per Mmbtu. 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 to estimate reserves is net of third party transportation, gathering and compression expense.


	Natural Gas			NGLs			Crude Oil			Natural Gas Equivalents ^(a)
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe)
Proved developed and undeveloped reserves:

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 ^(b)		3,566,526			122,722			23,239			4,442,290
Revisions		73,643			18,627			6,522			224,542
Extensions, discoveries and additions		1,304,324			26,591			4,915			1,493,357
Purchases		—			—			—			—
Property sales		(777,816	)		(19,852	)		(1,176	)		(903,983	)
Production		(157,001	)		(5,573	)		(1,968	)		(202,245	)

Balance, December 31, 2011		4,009,676			142,515			31,532			5,053,961

Proved developed reserves:
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

December 31, 2011		1,907,209			64,472			17,872			2,401,274

Proved undeveloped reserves:
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

December 31, 2011		2,102,467			78,043			13,660			2,652,687

^(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.

^(b)	Total proved reserves at December 31, 2010 includes 906,371 Mmcfe related to discontinued operations of which 408,710 Mmcfe is proved undeveloped.

During 2011, we added approximately 1.5 Tcfe of proved reserves from drilling activities and evaluations of proved areas, primarily in the Marcellus Shale. Approximately 87% of the 2011 reserve additions were attributable to natural gas. Revisions of previous estimates of 225 Bcfe were primarily positive performance revisions for natural gas properties, primarily in the Marcellus Shale.

During 2010, we added approximately 1.4 Tcfe of proved reserves from drilling activities and evaluations of proved areas primarily in the Marcellus Shale and the Barnett Shale. Approximately 77% of 2010 reserve additions were attributable to natural gas. Revisions of previous estimates of 148.6 Bcfe for the year ended December 31, 2010 included a positive revision of 40.5 Bcfe due to an increase in the average natural gas price used for the December 31, 2010 reserve estimation as compared to the price used in the previous year estimate. Revisions of previous estimates in 2010 also include positive performance revisions for natural gas properties primarily in the Barnett Shale.

During 2009, we added approximately 770 Bcfe of proved reserves from drilling activities and evaluations of proved areas primarily in the Barnett Shale and the Marcellus Shale. Approximately 81% of 2009 reserve additions were attributable to natural gas. Positive performance revisions of 89.9 Bcfe, primarily in the Marcellus Shale, were mostly offset by a negative price revision of 86.0 Bcfe due to a decrease in the natural gas price used for the December 31, 2009 reserve estimation as compared to the price used in the previous year estimate, resulting in a net positive revision of previous estimates of 3.9 Bcfe.

The following details the changes in proved undeveloped reserves for 2011 (Mmcfe):


Beginning proved undeveloped reserves at December 31, 2010	2,258,802
Undeveloped reserves transferred to developed	(364,150	)
Revisions	(15,098	)
Purchases/sales	(408,740	)
Extension and discoveries	1,181,873

Ending proved undeveloped reserves at December 31, 2011	2,652,687

Approximately $374.2 million was spent during 2011 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 $550.8 million in 2012, $805.3 million in 2013 and $829.2 million in 2014. Included in proved undeveloped reserves at December 31, 2011 are approximately 4,946 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 2016.

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, NGLs and oil reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs 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:

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

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 the year ended 2011, 2010 and 2009, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

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, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.

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, NGLs 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, NGL and oil reserves, which includes reserves associated with discontinued operations in 2010, is as follows and excludes cash flows associated with hedges outstanding at each of the respective reporting dates. Future cash inflows are net of third party transportation, gathering and compression expense.


	As of December 31,
	2011			2010
	(in thousands)
Future cash inflows	$	23,954,048		$	19,676,630
Future costs:
Production		(5,113,902	)		(4,305,292	)
Development		(3,230,577	)		(2,855,407	)

Future net cash flows before income taxes		15,609,569			12,515,931
Future income tax expense		(5,040,104	)		(3,923,264	)

Total future net cash flows before 10% discount		10,569,465			8,592,667
10% annual discount		(6,054,568	)		(5,113,541	)

Standardized measure of discounted future net cash flows	$	4,514,897		$	3,479,126

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


	As of December 31,
	2011			2010			2009
	(in thousands)
Revisions of previous estimates:
Changes in prices	$	422,080		$	957,994		$	(992,809	)
Revisions in quantities		326,240			190,874			4,124
Changes in future development costs		(346,378	)		(474,058	)		(375,344	)
Accretion of discount		464,735			259,280			340,025
Net change in income taxes		(400,690	)		(666,517	)		317,158
Purchases of reserves in place		—			160,580			—
Additions to proved reserves from extensions, discoveries and improved recovery		2,169,706			1,812,077			816,278
Production		(911,873	)		(744,354	)		(673,907	)
Development costs incurred during the period		513,551			298,624			316,523
Sales of natural gas and oil		(1,313,401	)		(243,551	)		(147,942	)
Timing and other		111,801			(162,912	)		(94,397	)

Net change for the year		1,035,771			1,388,037			(490,291	)
Beginning of year		3,479,126			2,091,089			2,581,380

End of year	$	4,514,897		$	3,479,126		$	2,091,089

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	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.
Discontinued Operations	Discontinued Operations During February 2011, we entered into an agreement to sell our Barnett Shale assets. Accordingly, in the first quarter 2011, we classified these assets and liabilities as discontinued operations in the accompanying consolidated balance sheets along with the historical results of the operations from such properties as discontinued operations, net of tax, in the accompanying statements of operations. See also Note 3 and Note 4 for more information regarding the sale of our Barnett Shale assets. Unless otherwise indicated, the information in these notes relate to our continuing operations.
Use of Estimates	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, natural gas liquids (“NGLs”) 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	Reclassifications Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation. This includes the reclassification of transportation and gathering revenue into other revenue. These reclassifications did not impact our net income from continuing operations, stockholders’ equity or cash flows.
Income per Common Share	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	Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, 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, Gas Imbalances and Receivables	Revenue Recognition, Gas Imbalances and Receivables Natural gas, NGL and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. As described in the revision section above, we are reporting our gathering and transportation costs in accordance with FASB Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we generally receive a net price from the purchaser (which is net of processing costs) which is also recorded in revenue at the net price we generally receive from the purchaser. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation expenses to a third party and receive proceeds from the purchaser with no transportation deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering and compression expense. 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 $4.0 million at December 31, 2011 compared to $5.0 million at December 31, 2010. During the year ended 2011, we recorded bad debt expense of $946,000 compared to $3.6 million in 2010 and $1.4 million in 2009. 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. At December 31, 2011, we had recorded a net liability of $50,000 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 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	Marketable Securities Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds are made up of investments which include equity securities and money market instruments.
Inventories	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 or repair operations. In 2011, we sold tubular goods and other inventory for proceeds of $8.0 million and recorded a gain of $359,000.
Natural Gas and Oil Properties	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 which is based upon the approximated relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices. 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 an asset group, 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. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12. Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization group are credited to the net book value of the 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 $748.6 million in 2011 compared to $648.1 million in 2010. Assets of discontinued operations include unproved properties of $163.7 million at December 31, 2010. We have recorded abandonment and impairment expense related to unproved properties from continuing operations of $79.7 million in 2011 compared to $49.7 million in 2010 and to $36.9 million in 2009.
Transportation and Field Assets	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. Transportation and field assets also includes other property and equipment such as buildings, furniture and fixtures, leasehold improvements, data processing and communication equipment. These items are generally depreciated by individual components on a straight line basis over their economic useful life, which is generally from 3 to 15 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $16.2 million in 2011 compared to $16.1 million in 2010 and $31.6 million in 2009. 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	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, 2011 include $39.4 million of unamortized debt issuance costs, $50.2 million of marketable securities held in our deferred compensation plans and $14.4 million of other investments including land.
Accounts Payable	Accounts Payable Included in accounts payable at December 31, 2011 and 2010, are liabilities of approximately $45.7 million and $97.2 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	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 (“Liability Awards”) and restricted stock unit awards (“Equity 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. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying statement of operations.
Derivative Financial Instruments and Hedging	Derivative Financial Instruments and Hedging All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs 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 derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. Through December 2011, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGLs 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 pre-tax gain of $11.6 million compared to a pre-tax gain of $5.4 million in 2009 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives. In 2011, we did not discontinue hedge accounting on any of our hedges. We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas, NGLs and oil production. Accordingly, we record changes in the fair value of our hedge derivative 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 hedge derivative contracts are reclassified out of AOCI and into natural gas, NGLs 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. At times, we have also entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we may enter into basis swap agreement that effectively fix our basis adjustments.
Asset Retirement Obligations	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 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. We do not recognize a deferred tax asset for excess tax benefits that have not been realized.
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income The following details the components of AOCI and related tax effects for the three years ended December 31, 2011. Amounts included in AOCI relate to our derivative activity (in thousands).
Recently Adopted	Accounting Pronouncements Implemented Recently Adopted In June 2011, the FASB issued Accounting Standards Update (“ASU”) No. 201-05, “Presentation of Comprehensive Income,” which was issued to enhance comparability between entities that report under U.S. GAAP and International Financial Reporting Standards (“IFRS”), and to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. ASU 2011-05 eliminates the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and requires an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Early adoption of the new guidance is permitted and full retrospective application is required. We adopted this new requirement in third quarter 2011 and since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.
Accounting Pronouncements Not Yet Adopted	Accounting Pronouncements Not Yet Adopted In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and IFRS. ASU 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance will require prospective application. The adoption of ASU 2011-04 is not expected to have a material effect on our consolidated financial statements, but may require additional disclosures.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of revision on Natural gas, NGL and oil sales, reported


	2010		2009
Natural gas, NGL and oil sales, previously reported	$	760,453	$	714,564
Revision of transportation, gathering and compression expenses		62,837		37,185

Natural gas, NGL and oil sales, reported	$	823,290	$	751,749

Summary of revision on Transportation, gathering and compression, reported


	2010		2009
Transportation, gathering and compression expenses, previously reported	$	—	$	—
Revision of transportation, gathering and compression expenses		62,837		37,185

Transportation, gathering and compression, reported	$	62,837	$	37,185

Accumulated Other Comprehensive Income (Loss)


	Gross			Tax Effect			Net of Tax
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
Contract settlements reclassified to income		(132,201	)		50,005			(82,196	)
Change in unrealized deferred hedging gains		275,817			(104,464	)		171,353

Accumulated other comprehensive income at December 31, 2011	$	254,678		$	(98,051	)	$	156,627

Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2011

Discontinued Operations [Abstract]

Components of discontinued operations


	Year Ended December 31,
	2011		2010			2009
Revenues and other income:
Natural gas, NGL and oil sales	$	59,185	$	157,778		$	139,357
Transportation and gathering		6		35			—
Gain on the sale of assets		4,771		955			—
Other		4		32			3

Total revenues and other income		63,966		158,800			139,360

Costs and expenses:
Direct operating		10,080		35,328			34,960
Transportation, gathering and compression		5,257		8,624			14,000
Production and ad valorem taxes		1,309		7,545			6,633
Exploration		37		581			2,209
Abandonment and impairment of unproved properties		—		20,233			76,603
Interest expense ^(a)		14,791		40,527			42,106
Depletion, depreciation and amortization		8,894		88,269			106,354
Impairment of proved properties		—		463,244			—

Total costs and expenses		40,368		664,351			282,865

Income (loss) before income taxes		23,598		(505,551	)		(143,505	)

Income tax expense (benefit)
Current		—		—			—
Deferred		8,278		(177,597	)		(50,655	)

		8,278		(177,597	)		(50,655	)

Net income (loss) from discontinued operations	$	15,320	$	(327,954	)	$	(92,850	)

^(a)	Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

Composition of assets and liabilities of discontinued


	December 31,
	2011		2010
Composition of assets of discontinued operations:
Natural gas properties and oil properties, net	$	—	$	838,044
Transportation and field assets, net		—		684
Accounts receivable		—		30,575
Unrealized derivative gain		—		8,195
Inventory and other		—		81

Total current assets of discontinued operations	$	—	$	877,579

Composition of liabilities of discontinued operations:
Accounts payable	$	—	$	23,366
Accrued liabilities		653		10,871
Asset retirement obligations		—		—

Total current liabilities of discontinued operations	$	653	$	34,237

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

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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

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


	Year Ended December 31,
	2011			2010			2009
Federal statutory tax rate		35.0	%		35.0	%		35.0	%
State		7.0			(0.2	)		20.6
Non-deductible executive compensation		3.5			0.2			—
Valuation allowance		(0.4	)		1.4			(1.9	)
Other		0.3			0.1			0.3

Consolidated effective tax rate		45.4	%		36.5	%		54.0	%

Income tax provision attributable to income from continuing operations


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Current:
U.S. federal	$	—	$	—		$	(1,000	)
U.S. state and local		637		(836	)		364

	$	637	$	(836	)	$	(636	)

Deferred:
U.S. federal	$	30,055	$	51,280		$	29,085
U.S. state and local		4,865		466			17,344

	$	34,920	$	51,746		$	46,429

Total income tax expense	$	35,557	$	50,910		$	45,793

Significant components of deferred tax assets and liabilities


	December 31,
	2011			2010
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	8,607		$	5,857
Current portion of asset retirement obligation		2,011			1,579
Other		1,423			4,106
Current portion of net operating loss carryforward		—			17,586

Total current		12,041			29,128

Non-current
Net operating loss carryforward		63,568			85,120
Deferred compensation		64,176			49,933
AMT credits and other credits		3,505			3,211
Non-current portion of asset retirement obligation		30,358			23,127
Cumulative unrealized mark-to-market loss		2,373			9,826
Other		22,076			23,481
Valuation allowance		(4,534	)		(4,841	)

Total non-current		181,522			189,857

Deferred tax liabilities:
Current
Net unrealized gain in AOCI related to hedge derivatives		(68,636	)		(40,976	)

Total current		(68,636	)		(40,976	)

Non-current
Depreciation, depletion and investments		(862,597	)		(858,502	)
Net unrealized gain in AOCI related to hedge derivatives		(29,415	)		(2,616	)
Other		—			(780	)

Total non-current		(892,012	)		(861,898	)

Net deferred tax liability	$	(767,085	)	$	(683,889	)

Income (Loss) Per Common Share (Tables)

12 Months Ended

Dec. 31, 2011

Income (Loss) Per Common Share [Abstract]

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


	Twelve Months Ended December 31, 2011									Twelve Months Ended December 31, 2010									Twelve Months Ended December 31, 2009
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total			Continuing Operations		Discontinued Operations			Total
Income (loss) as reported	$	42,706		$	15,320		$	58,026		$	88,698		$	(327,954	)	$	(239,256	)	$	38,980	$	(92,850	)	$	(53,870	)
Participating basic earnings ^(a)		(763	)		(274	)		(1,037	)		(1,574	)		1,120			(454	)		—		—			—

Basic income (loss) attributed to common shareholders		41,943			15,046			56,989			87,124			(326,834	)		(239,710	)		38,980		(92,850	)		(53,870	)
Reallocation of participating earnings ^(a)		3			2			5			11			(11	)		—			—		—			—

Diluted income (loss) attributed to common shareholders	$	41,946		$	15,048		$	56,994		$	87,135		$	(326,845	)	$	(239,710	)	$	38,980	$	(92,850	)	$	(53,870	)

Income (loss) per common share:
Basic	$	0.26		$	0.10		$	0.36		$	0.56		$	(2.09	)	$	(1.53	)	$	0.25	$	(0.60	)	$	(0.35	)
Diluted	$	0.26		$	0.10		$	0.36		$	0.55		$	(2.07	)	$	(1.52	)	$	0.24	$	(0.58	)	$	(0.34	)

^(a)

Basic weighted average common shares outstanding to diluted weighted average common shares outstanding


	Year Ended December 31,
	2011		2010		2009
Denominator:
Weighted average common shares outstanding – basic		158,030		156,874		154,514
Effect of dilutive securities:
Director and employee stock options and SARs		1,411		1,554		4,264

Weighted average common shares outstanding – diluted		159,441		158,428		158,778

Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2011

Suspended Exploratory Well Costs [Abstract]

Suspended Exploratory Well Costs


	2011			2010			2009
Balance at beginning of period	$	23,908		$	19,052		$	47,623
Additions to capitalized exploratory well costs pending the determination of proved reserves		86,996			28,897			26,216
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(17,516	)		(24,041	)		(52,849	)
Capitalized exploratory well costs charged to expense		—			—			(1,938	)

Balance at end of period		93,388			23,908			19,052
Less exploratory well costs that have been capitalized for a period of one year or less		(83,860	)		(13,181	)		(10,778	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	9,528		$	10,727		$	8,274

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

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


	Total		2011		2010		2009		2008
Capitalized exploratory well costs that have been capitalized for more than one year	$	9,528	$	414	$	4,707	$	2,884	$	1,523

Indebtedness (Tables)

12 Months Ended

Dec. 31, 2011

Indebtedness [Abstract]

Debt Outstanding


	December 31,
	2011		2010
Bank debt (2.2%)	$	187,000	$	274,000

Senior subordinated notes:
6.375% senior subordinated notes due 2015		—		150,000
7.5% senior subordinated notes due 2016, net of $317 discount		—		249,683
7.5% senior subordinated notes due 2017		250,000		250,000
7.25% senior subordinated notes due 2018		250,000		250,000
8.0% senior subordinated notes due 2019, net of $12,033 and $13,147 discount, respectively		287,967		286,853
6.75% senior subordinated notes due 2020		500,000		500,000
5.75% senior subordinated notes due 2021		500,000		—

Total debt	$	1,974,967	$	1,960,536

Schedule for the long-term debt outstanding


	Year Ended December 31,
2012	$	—
2013		—
2014		—
2015		—
2016		187,000
2017		250,000
Thereafter		1,537,967

	$	1,974,967

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

+ Details

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations


	2011			2010
Beginning of period – continuing operations	$	60,693		$	76,589
Liabilities incurred		3,265			1,495
Acquisitions-continuing operations		—			556
Liabilities settled		(4,717	)		(2,331	)
Disposition of wells		(716	)		(12,891	)
Accretion expense-continuing operations		5,488			5,137
Change in estimate		20,797			(7,862	)

End of period – continuing operations		84,810			60,693

Less current portion		(5,005	)		(4,020	)

Long-term asset retirement obligations – continuing operations	$	79,805		$	56,673

Asset retirement obligations-discontinued operations	$	—		$	1,980

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2011

Capital Stock [Abstract]

Capital Stock


	Year Ended December 31,
	2011		2010		2009
Beginning balance		159,909,052		158,118,937		155,375,487
Shares issued in lieu of cash bonuses		—		—		184,926
Stock options/SARs exercised		862,774		991,988		1,384,861
Restricted stock grants		326,591		405,127		413,353
Issued for acreage purchases		—		380,229		743,737
Treasury shares		33,130		12,771		16,573

Ending balance		161,131,547		159,909,052		158,118,937

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Activities [Abstract]

Derivative volumes hedged and average hedge prices


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2012	Collars	234,887 Mmbtu/day	$ 4.99–$ 5.50
2013	Collars	240,000 Mmbtu/day	$ 4.73–$ 5.20
2014	Collars	90,000 Mmbtu/day	$ 4.25–$ 4.85
2012	Swaps	182,986 Mmbtu/day	$4.06

Crude Oil
2012	Collars	2,000 bbls/day	$ 70.00–$ 80.00
2013	Collars	3,000 bbls/day	$ 90.60–$ 100.00
2014	Collars	2,000 bbls/day	$ 85.55–$ 100.00
2012	Call options	4,700 bbls/day	$85.00
2013	Swaps	3,000 bbls/day	$95.55
2014	Swaps	2,000 bbls/day	$92.75

NGLs (Natural Gasoline)
2012	Swaps	12,000 bbls/day	$96.28
2013	Swaps	6,000 bbls/day	$87.33

Derivative Fair Value Income


	2011			2010			2009
Change in fair value of derivatives that do not qualify for hedge accounting ^(a)	$	15,762		$	(2,086	)	$	(115,909	)
Realized gain (loss) on settlement–natural gas ^(a) ^(b)		14,743			35,988			171,998
Realized gain (loss) on settlement–oil ^{(a) (b)}		(9,574	)		—			7,304
Realized gain (loss) on settlement–NGL ^{(a) (b)}		9,612			—			—
Realized gain on early settlement of oil derivatives		—			15,697			—
Hedge ineffectiveness–realized		7,361			(352	)		4,749
–unrealized		2,183			2,387			(1,696	)

Derivative fair value income	$	40,087		$	51,634		$	66,446

^(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.

Combined fair value of derivatives, by Consolidated balance sheet


	December 31,
	2011			2010
Derivative assets:
Natural gas–swaps	$	54,162		$	—
–collars		228,228			155,159
–collars – discontinued operations		—			8,195
Crude oil–swaps		(263	)		—
–collars		(16,607	)		—
–call options		(29,348	)		(31,904	)
NGL–swaps		15,328			—

	$	251,500		$	131,450

Derivative liabilities:
Natural gas–collars	$	—		$	27,032
–basis swaps		—			(352	)
Crude oil–collars		—			(12,051	)
–call options		—			(28,393	)
NGL–swaps		(173	)		—

	$	(173	)	$	(13,764	)

Derivative Gross Assets and Gross Liabilities


	December 31, 2011								December 31, 2010
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying Value		Carrying Value			Net Carrying Value			Carrying Value		Carrying Value			Net Carrying Value
Derivatives that qualify for cash flow hedge accounting :
Swaps ^(a)	$	54,318	$	(419	)	$	53,899		$	—	$	—		$	—
Collars ^(a)		228,228		(1,954	)		226,274			164,933		—			164,933
Collars – discontinued Operations ^(b)		—		—			—			8,195		—			8,195

	$	282,546	$	(2,373	)	$	280,173		$	173,128	$	—		$	173,128

Derivatives that do not qualify for hedge accounting :
Swaps ^(a)	$	17,949	$	(2,794	)	$	15,155		$	—	$	—		$	—
Collars ^(a)		—		(14,653	)		(14,653	)		17,259		(12,052	)		5,207
Call options ^(a)		—		(29,348	)		(29,348	)		—		(60,297	)		(60,297	)
Basis swaps ^(a)		—		—			—			—		(352	)		(352	)

	$	17,949	$	(46,795	)	$	(28,846	)	$	17,259	$	(72,701	)	$	(55,442	)

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

^(b)	Included in assets of discontinued operations.

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


	Year Ended December 31,
	Change in Hedge Derivative Fair Value						Realized Gain Reclassified from OCI into Revenue ^(a)
	2011			2010			2011			2010
Swaps	$	51,997		$	—		$	—		$	—
Collars		223,408			157,447			123,594			64,772
Collars – discontinued operations		412			8,195			8,607			—
Income taxes		(104,464	)		(64,662	)		(50,005	)		(24,841	)

	$	171,353		$	100,980		$	82,196		$	39,931

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

Effects of non-hedge derivatives on consolidated statement of operations


	Year Ended December 31,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)									Gain (Loss) Recognized in Income (Ineffective Portion)						Derivative Fair Value Income
	2011			2010			2009			2011		2010		2009		2011			2010			2009
Swaps	$	24,767		$	—		$	63,755		$	—	$	—	$	—	$	24,767		$	—		$	63,755
Collars		5,266			65,996			33,859			9,544		2,035		3,053		14,810			68,031			36,912
Call options		553			(15,895	)		—			—		—		—		553			(15,895	)		—
Basis swaps		(43	)		(502	)		(34,221	)		—		—		—		(43	)		(502	)		(34,221	)

Total	$	30,543		$	49,599		$	63,393		$	9,544	$	2,035	$	3,053	$	40,087		$	51,634		$	66,446

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

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


	Fair Value Measurements at December 31, 2011 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2011
Trading securities held in the deferred compensation plans	$	50,237	$	—		$	—	$	50,237
Derivatives–swaps		—		69,054			—		69,054
–collars		—		211,621			—		211,621
–call options		—		(29,348	)		—		(29,348	)


	Fair Value Measurements at December 31, 2010 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2010
Trading securities held in the deferred compensation plans	$	47,794	$	—		$	—	$	47,794
Derivatives–collars		—		170,140			—		170,140
–collars – discontinued operations		—		8,195			—		8,195
–call options		—		(60,297	)		—		(60,297	)
–basis swaps		—		(352	)		—		(352	)

Values of assets measured at fair value on nonrecurring basis


	Year Ended December 31,
	2011				2010				2009
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties – continuing operations	$	24,388	$	38,681	$	16,075	$	6,505	$	1,244	$	930
Natural gas and oil properties – discontinued operations		—		—		835,913		463,244		—		—
Equity investments		—		—		—		—		2,895		8,950

Carrying Amounts and Fair Values of Financial Instruments


	December 31, 2011						December 31, 2010
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and call options	$	251,500		$	251,500		$	123,255		$	123,255
Commodity collars – discontinued operations		—			—			8,195			8,195
Marketable securities^(a)		50,237			50,237			47,794			47,794
Liabilities:
Commodity swaps, collars, call options and basis swaps		(173	)		(173	)		(13,764	)		(13,764	)
Bank credit facility^(b)		(187,000	)		(187,000	)		(274,000	)		(274,000	)
6.375% senior subordinated notes due 2015^(b)		—			—			(150,000	)		(153,000	)
7.5% senior subordinated notes due 2016^(b)		—			—			(249,683	)		(259,375	)
7.5% senior subordinated notes due 2017^(b)		(250,000	)		(265,625	)		(250,000	)		(263,438	)
7.25% senior subordinated notes due 2018^(b)		(250,000	)		(267,500	)		(250,000	)		(263,750	)
8.0% senior subordinated notes due 2019^(b)		(287,967	)		(334,500	)		(286,853	)		(326,625	)
6.75% senior subordinated notes due 2020^(b)		(500,000	)		(555,000	)		(500,000	)		(515,625	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(541,250	)		—			—

^(a)	Marketable securities are held in our deferred compensation plans that are actively traded on major exchanges.

^(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.

- Definition

Tabular disclosure of the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such certain disclosures about the financial instruments, assets, and liabilities include: (1) the fair value of the required items together with their carrying amounts (as appropriate) and (2) the methodology and assumptions used in developing such estimates of fair value.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 14
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15
-Subparagraph b-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32
-Subparagraph a, c(1), c(2), c(3), d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph c(2), d, e, f
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 19
-Subparagraph a, b, c(1), d(1)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13433-108611

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13467-108611

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13476-108611

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19207-110258

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6447952&loc=d3e13220-108610

+ Details

Stock Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2011

Stock-Based Compensation Plans [Abstract]

Stock option and SARs activities


	Shares			Weighted Average Exercise Price
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
Granted		843,485			51.17
Exercised		(2,511,989	)		32.69
Expired/forfeited		(234,726	)		52.65

Outstanding at December 31, 2011		4,558,609		$	41.47

Outstanding stock options and SARs

The following table shows information with respect to stock options and SARs outstanding and exercisable at December 31, 2011:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$1.29 – $ 9.99		619,716		0.29	$	3.41		619,716	$	3.41
10.00 – 19.99		15,435		3.73		19.63		15,435		19.63
20.00 – 29.99		—		—		—		—		—
30.00 – 39.99		808,975		1.52		34.90		506,868		35.30
40.00 – 49.99		1,968,934		3.12		45.28		643,665		43.63
50.00 – 59.99		803,137		3.29		54.39		310,905		57.64
60.00 – 69.99		13,542		1.65		66.04		12,677		65.91
70.00 – 75.00		328,870		1.39		75.00		328,870		75.00

Total		4,558,609		2.35	$	41.47		2,438,136	$	37.66

Weighted average grant date fair value of SARs


	2011			2010			2009
Weighted average exercise price per share	$	51.17		$	46.09		$	36.90
Expected annual dividends per share		0.31	%		0.35	%		0.44	%
Expected life in years		3.7			3.6			3.5
Expected volatility		47	%		49	%		58	%
Risk-free interest rate		1.4	%		1.6	%		1.5	%
Weighted average grant date fair value	$	18.22		$	17.01		$	15.42

Restricted stock and Restricted stock units outstanding

A summary of the status of our non-vested restricted stock outstanding at December 31, 2011 is summarized below:


	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2008		—		$	—		473,547		$	48.50
Granted		—			—		685,578			39.99
Vested		—			—		(521,536	)		40.91
Forfeited		—			—		(10,400	)		40.83

Outstanding at December 31, 2009		—			—		627,189			45.64
Granted		—			—		413,422			45.83
Vested		—			—		(439,361	)		46.90
Forfeited		—			—		(18,499	)		46.04

Outstanding at December 31, 2010		—			—		582,751			44.81
Granted		331,209			49.56		349,840			51.17
Vested		(88,854	)		49.37		(416,055	)		45.50
Forfeited		(20,746	)		49.45		(29,292	)		45.04

Outstanding at December 31, 2011		221,609		$	49.64		487,244		$	48.76

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Net cash provided from operating activities included:
Income taxes paid (refunded from) to taxing authorities	$	675	$	(1,359	)	$	170
Interest paid		133,103		116,766			108,685

Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net		24,061		(6,370	)		4,985
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, 2011

Commitments and Contingencies [Abstract]

Future minimum rental commitments


	Operating Lease Obligations
2012	$	12,843
2013		11,648
2014		10,923
2015		10,755
2016		8,438
Thereafter		27,701
Sublease rentals		(963	)

	$	81,345

Future minimum transportation fees


	Transportation and Gathering Contracts
2012	$	103,030
2013		102,693
2014		102,221
2015		99,298
2016		99,424
Thereafter		506,798

	$	1,013,464

Future Delivery Commitments


Year Ending December 31,	Natural Gas and Ethane (mcfe per day)
2012		1,370
2013		33,434
2014		96,174
2015		98,913
2016		99,589
Thereafter		90,000

- Definition

Tabular disclosure of a lessee's leasing arrangements including: (1) the basis on which contingent rental payments are determined, (2) the existence and terms of renewal or purchase options and escalation clauses, (3) restrictions imposed by lease arrangements, such as those concerning dividends, additional debt, and further leasing, (4) rent holidays, rent concessions, or leasehold improvement incentives and unusual provisions or conditions. Disclosure may also include the specific period used to amortize material leasehold improvements made at the inception of the lease or during the lease term. Additionally, for operating leases having initial or remaining noncancelable lease terms in excess of one year: (a) future minimum rental payments required as of the date of the latest balance sheet presented, in the aggregate and for each of the five succeeding fiscal years, (b) the total of minimum rentals to be received in the future under noncancelable subleases as of the date of the latest balance sheet presented, and (c) for all operating leases, rental expense for each period for which an income statement is presented, with separate amounts for minimum rentals, contingent rentals, and sublease rentals. Rental payments under leases with terms of a month or less that were not renewed need not be included.

+ References + Details

Office Closing and Exit Activities (Tables)

12 Months Ended

Dec. 31, 2011

Office Closing and Exit Activities [Abstract]

Exit activities included in accrued liabilities in consolidated balance sheet


	2011			2010			2009
Beginning balance	$	1,092		$	1,568		$	—
Accrued one-time termination costs		—			5,138			1,895
Office lease		—			514			252
Payments		(1,040	)		(6,128	)		(579	)

Ending balance	$	52		$	1,092		$	1,568

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data


	2011
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	251,963		$	285,353		$	304,230		$	331,720		$	1,173,266
Derivative fair value (loss) income		(40,834	)		53,039			65,761			(37,879	)		40,087
Gain (loss) on the sale of assets		139			(1,622	)		203			3,540			2,260
Other		1,390			(1,475	)		442			2,686			3,043

Total revenue and other income		212,658			335,295			370,636			300,067			1,218,656

Costs and expenses:
Direct operating		28,717			28,509			29,828			25,918			112,972
Transportation, gathering and compression		25,082			28,666			32,431			34,576			120,755
Production and ad valorem taxes		6,879			7,550			7,317			5,920			27,666
Exploration		27,187			11,592			17,606			24,982			81,367
Abandonment and impairment of unproved properties		16,537			18,900			16,627			27,639			79,703
General and administrative		33,959			39,120			35,907			42,205			151,191
Deferred compensation plan		30,630			(5,778	)		8,717			9,640			43,209
Interest expense		24,779			31,383			34,181			34,709			125,052
Loss on early extinguishment of debt		—			18,580			(4	)		—			18,576
Depletion, depreciation and amortization		72,216			78,294			93,619			97,092			341,221
Impairment of proved properties		—			—			38,681			—			38,681

Total costs and expenses		265,986			256,816			314,910			302,681			1,140,393

(Loss) income from continuing operations before income taxes		(53,328	)		78,479			55,726			(2,614	)		78,263

Income tax (benefit) expense
Current		—			8			(7	)		636			637
Deferred		(19,897	)		32,695			22,547			(425	)		34,920

		(19,897	)		32,703			22,540			211			35,557

(Loss) income from continuing operations		(33,431	)		45,776			33,186			(2,825	)		42,706
Discontinued operations, net of taxes		8,398			5,517			1,569			(164	)		15,320

Net (loss) income	$	(25,033	)	$	51,293		$	34,755		$	(2,989	)	$	58,026

(Loss) income per common share:
Basic-(loss) income from continuing operations	$	(0.21	)	$	0.28		$	0.21		$	(0.02	)	$	0.26
-discontinued operations		0.05			0.04			0.01			—			0.10

-net (loss) income	$	(0.16	)	$	0.32		$	0.22		$	(0.02	)	$	0.36

Diluted-(loss) income from continuing operations	$	(0.21	)	$	0.28		$	0.20		$	(0.02	)	$	0.26
-discontinued operations		0.05			0.04			0.01			—			0.10

-net (loss) income	$	(0.16	)	$	0.32		$	0.21		$	(0.02	)	$	0.36


	2010
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	200,633		$	187,523		$	203,255		$	231,879		$	823,290
Derivative fair value income (loss)		42,333			6,546			9,981			(7,226	)		51,634
Gain (loss) on the sale of assets		67,913			10,176			67			(1,514	)		76,642
Other		506			1,300			(2,650	)		914			70

Total revenue and other income		311,385			205,545			210,653			224,053			951,636

Costs and expenses:
Direct operating		21,836			21,171			25,535			27,732			96,274
Transportation, gathering and compression		12,960			14,370			15,498			20,009			62,837
Production and ad valorem taxes		6,542			5,663			6,903			6,999			26,107
Exploration		14,139			14,420			15,225			16,722			60,506
Abandonment and impairment of unproved properties		6,551			9,727			14,435			19,025			49,738
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		20,931			21,271			23,363			25,100			90,665
Loss on early extinguishment of debt		—			—			5,351			—			5,351
Depletion, depreciation and amortization		64,807			67,813			69,730			72,888			275,238
Impairment of proved properties		6,505			—			—			—			6,505

Total costs and expenses		184,667			176,136			207,216			244,009			812,028

Income (loss) from continuing operations before income taxes		126,718			29,409			3,437			(19,956	)		139,608

Income tax expense (benefit)
Current		—			—			(10	)		(826	)		(836	)
Deferred		49,012			11,763			794			(9,823	)		51,746

		49,012			11,763			784			(10,649	)		50,910

Income (loss) from continuing operations		77,706			17,646			2,653			(9,307	)		88,698
Discontinued operations, net of taxes		(127	)		(8,594	)		(10,821	)		(308,412	)		(327,954	)

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

Income (loss) per common share:
Basic-income (loss) from continuing operations	$	0.49		$	0.11		$	0.02		$	(0.06	)	$	0.56
-discontinued operations		—			(0.05	)		(0.07	)		(1.96	)		(2.09	)

-net income (loss)	$	0.49		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.53	)

Diluted-income (loss) from continuing operations	$	0.48		$	0.11		$	0.02		$	(0.06	)	$	0.55
-discontinued operations		—			(0.05	)		(0.07	)		(1.96	)		(2.07	)

-net income (loss)	$	0.48		$	0.06		$	(0.05	)	$	(2.02	)	$	(1.52	)

Principal Unconsolidated Investees (unaudited)


Company	December 31, 2011 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 (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

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

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

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


	December 31,
	2011			2010			2009
				(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	6,035,429		$	4,742,248		$	4,144,007
Unproved properties		748,598			648,143			572,471

Total		6,784,027			5,390,391			4,716,478
Accumulated depreciation, depletion and amortization		(1,626,461	)		(1,306,378	)		(1,164,843	)

Net capitalized costs	$	5,157,566		$	4,084,013		$	3,551,635

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

Costs Incurred for Property Acquisition, Exploration and Development

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


	Year Ended December 31,
	2011		2010			2009
	(in thousands)
Acquisitions:
Unproved leasehold	$	—	$	3,697		$	—
Proved oil and gas properties		—		130,767			—
Asset retirement obligations		—		556			—
Acreage purchases ^(b)		220,576		151,572			162,172
Development		1,007,049		727,720			374,970
Exploration:
Drilling		226,920		50,433			49,029
Expense		77,259		56,298			39,873
Stock-based compensation expense		4,108		4,209			4,817
Gas gathering facilities:
Development		53,387		19,627			27,937

Subtotal		1,589,299		1,144,879			658,798
Asset retirement obligations		24,061		(6,370	)		4,985

Total – continuing operations		1,613,360		1,138,509			663,783
Discontinued operations		3,241		73,369			150,461

Total costs incurred	$	1,616,601	$	1,211,878		$	814,244

^(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.

Proved developed and undeveloped reserves


	Natural Gas			NGLs			Crude Oil			Natural Gas Equivalents ^(a)
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe)
Proved developed and undeveloped reserves:

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 ^(b)		3,566,526			122,722			23,239			4,442,290
Revisions		73,643			18,627			6,522			224,542
Extensions, discoveries and additions		1,304,324			26,591			4,915			1,493,357
Purchases		—			—			—			—
Property sales		(777,816	)		(19,852	)		(1,176	)		(903,983	)
Production		(157,001	)		(5,573	)		(1,968	)		(202,245	)

Balance, December 31, 2011		4,009,676			142,515			31,532			5,053,961

Proved developed reserves:
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

December 31, 2011		1,907,209			64,472			17,872			2,401,274

Proved undeveloped reserves:
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

December 31, 2011		2,102,467			78,043			13,660			2,652,687

^(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.

^(b)	Total proved reserves at December 31, 2010 includes 906,371 Mmcfe related to discontinued operations of which 408,710 Mmcfe is proved undeveloped.

Changes in proved undeveloped reserves for 2011 (Mmcfe)

The following details the changes in proved undeveloped reserves for 2011 (Mmcfe):


Beginning proved undeveloped reserves at December 31, 2010	2,258,802
Undeveloped reserves transferred to developed	(364,150	)
Revisions	(15,098	)
Purchases/sales	(408,740	)
Extension and discoveries	1,181,873

Ending proved undeveloped reserves at December 31, 2011	2,652,687

Standardized measure of discounted future net cash flows


	As of December 31,
	2011			2010
	(in thousands)
Future cash inflows	$	23,954,048		$	19,676,630
Future costs:
Production		(5,113,902	)		(4,305,292	)
Development		(3,230,577	)		(2,855,407	)

Future net cash flows before income taxes		15,609,569			12,515,931
Future income tax expense		(5,040,104	)		(3,923,264	)

Total future net cash flows before 10% discount		10,569,465			8,592,667
10% annual discount		(6,054,568	)		(5,113,541	)

Standardized measure of discounted future net cash flows	$	4,514,897		$	3,479,126

Changes in Discounted future net cash flows


	As of December 31,
	2011			2010			2009
	(in thousands)
Revisions of previous estimates:
Changes in prices	$	422,080		$	957,994		$	(992,809	)
Revisions in quantities		326,240			190,874			4,124
Changes in future development costs		(346,378	)		(474,058	)		(375,344	)
Accretion of discount		464,735			259,280			340,025
Net change in income taxes		(400,690	)		(666,517	)		317,158
Purchases of reserves in place		—			160,580			—
Additions to proved reserves from extensions, discoveries and improved recovery		2,169,706			1,812,077			816,278
Production		(911,873	)		(744,354	)		(673,907	)
Development costs incurred during the period		513,551			298,624			316,523
Sales of natural gas and oil		(1,313,401	)		(243,551	)		(147,942	)
Timing and other		111,801			(162,912	)		(94,397	)

Net change for the year		1,035,771			1,388,037			(490,291	)
Beginning of year		3,479,126			2,091,089			2,581,380

End of year	$	4,514,897		$	3,479,126		$	2,091,089

- Definition

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

+ References + Details

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of revisions
Natural gas, NGL and oil sales	$ 331,720	$ 304,230	$ 285,353	$ 251,963	$ 231,879	$ 203,255	$ 187,523	$ 200,633	$ 1,173,266	$ 823,290	$ 751,749
Natural gas, NGL and oil sales, previously reported [Member]
Summary of revisions
Natural gas, NGL and oil sales										760,453	714,564
Revision of transportation, gathering and compression expenses [Member]
Summary of revisions
Natural gas, NGL and oil sales										$ 62,837	$ 37,185

Summary of Significant Accounting Policies (Details 1) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revision of corresponding amounts have been reflected in transportation, gathering and compression expenses
Transportation, gathering and compression, reported	$ 34,576	$ 32,431	$ 28,666	$ 25,082	$ 20,009	$ 15,498	$ 14,370	$ 12,960	$ 120,755	$ 62,837	$ 37,185
Transportation, gathering and compression expenses, previously reported [Member]
Revision of corresponding amounts have been reflected in transportation, gathering and compression expenses
Transportation, gathering and compression, reported										0	0
Revision of transportation, gathering and compression expenses [Member]
Revision of corresponding amounts have been reflected in transportation, gathering and compression expenses
Transportation, gathering and compression, reported										$ 62,837	$ 37,185

Summary of Significant Accounting Policies (Details 2) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accumulated Other Comprehensive Income (Loss)
Beginning Balance, Gross	$ 111,062	$ 10,192	$ 122,252
Beginning Balance, Tax Effect	(43,592)	(3,771)	(44,745)
Beginning Balance, Net of Tax	67,470	6,421	77,507
Contract settlements reclassified to income, before tax	(132,201)	(64,772)	(203,119)
Contract settlements reclassified to income, Tax Effect	50,005	24,841	75,154
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss), net of taxes	(82,196)	(39,931)	(127,965)
Change in unrealized deferred hedging gains, Before Tax	275,817	165,642	91,059
Change in unrealized deferred hedging gains, Tax Effect	(104,464)	(64,662)	(34,180)
Change in unrealized deferred hedging gains (losses), net of taxes	171,353	100,980	56,879
Ending Balance, Gross	254,678	111,062	10,192
Ending Balance, Tax Effect	(98,051)	(43,592)	(3,771)
Ending Balance, Net of Tax	$ 156,627	$ 67,470	$ 6,421

Summary of Significant Accounting Policies (Details Textual)	3 Months Ended								12 Months Ended
	Dec. 31, 2011 USD ($)	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2011 USD ($) yr Mcf	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Summary of Significant Accounting Policies (Textual) [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 4,015,000				$ 5,001,000				$ 4,015,000	$ 5,001,000
Allowance for bad debts									946,000	3,608,000	$ 1,351,000
Liability due to insufficient reserves	50,000								$ 50,000
Maturity period of cash and cash equivalents									3 months or less
MCF of gas equating to one barrel of oil \| Mcf									6
Proceeds from sale of tubular goods and other inventory									$ 8,000,000
Gain on sale of tubular goods and other inventory									359,000
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	748,600,000				648,100,000				748,600,000	648,100,000
Net book value of unproved properties discontinued operations					163,700,000					163,700,000
Abandonment and impairment of unproved properties	27,639,000	$ 16,627,000	$ 18,900,000	$ 16,537,000	19,025,000	$ 14,435,000	$ 9,727,000	$ 6,551,000	79,703,000	49,738,000	36,935,000
Depreciation expense									16,200,000	16,100,000	31,600,000
Accelerated depreciation expense											10,300,000
Unamortized debt issuance costs	39,400,000								39,400,000
Marketable securities	50,200,000								50,200,000
Other investments	14,400,000								14,400,000
Bank Over draft balance included in Accounts Payable	$ 45,700,000				$ 97,200,000				45,700,000	97,200,000
Gain loss as a result of the discontinuance of hedge accounting treatment for derivatives									$ 0	$ 11,600,000	$ 5,400,000
Gas transportation and gathering systems [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Useful life of assets, Minimum \| yr									10
Useful life of assets, Maximum \| yr									15
Associated assets [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Useful life of assets, Minimum \| yr									5
Useful life of assets, Maximum \| yr									7
Other property and equipment [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Useful life of assets, Minimum \| yr									3
Useful life of assets, Maximum \| yr									15

Dispositions and Acquisitions (Details Textual) - USD ($)	1 Months Ended		3 Months Ended					6 Months Ended	9 Months Ended	12 Months Ended
	Jun. 30, 2010	Mar. 31, 2010	Sep. 30, 2011	Mar. 31, 2011	Mar. 31, 2010	Dec. 31, 2009	Jun. 30, 2009	Jun. 30, 2011	Sep. 30, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accumulated other comprehensive income (loss)						$ 6,421,000				$ 156,627,000	$ 67,470,000	$ 6,421,000	$ 77,507,000
Impairment on Oil and Gas Properties			$ 38,681,000		$ 6,505,000					38,681,000	6,505,000	930,000
Proceeds from sale of oil and gas properties										53,926,000	327,765,000	234,076,000
Gain from sale of oil and gas properties				$ 0
Proceeds used to repay outstanding borrowings under credit facility										974,826,000	1,105,000,000	$ 1,076,000,000
Purchase price allocated to proved properties											130,767,000
Acquisitions of unproved property											3,697,000
Ohio Properties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties											323,000,000
Gain from sale of oil and gas properties											$ 77,600,000
Proceeds used to repay outstanding borrowings under credit facility									$ 135,000,000
Percentage of Ohio sale closed		90.00%
Barnett Shale Properties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the sale of natural gas properties										889,300,000
Gain or loss on sale of natural gas properties										4,800,000
Pretax gain										25,100,000
Loss on derivative contracts								$ (1,700,000)
Proceeds from derivative contract								$ 40,000,000
East Texas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties			31,200,000							31,200,000
Proceeds from sale of oil and gas properties			10,500,000
Pennsylvania [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties			5,400,000
Proceeds from exchange of unproved property										11,500,000
Gain from sale of oil and gas properties			$ 0
Gain on exchange of acreage										$ 4,500,000
Marcellus Shale Acreage [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of acreage						11,200,000
Gain on sale of acreage						10,400,000
Virginia Properties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisitions of producing and unproved properties	$ 134,500,000
Purchase price allocated to proved properties	131,300,000
Acquisitions of unproved property	$ 3,700,000
West Texas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties							$ 181,800,000
Gain from sale of oil and gas properties							$ 0
New York [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties						36,300,000
Gain from sale of oil and gas properties						$ 0
Low pressure pipeline [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of pipeline				14,700,000
Gain from sale of pipeline				$ 0

Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Discontinued Operations (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other income:
Natural gas, NGL and oil sales	$ 331,720	$ 304,230	$ 285,353	$ 251,963	$ 231,879	$ 203,255	$ 187,523	$ 200,633	$ 1,173,266	$ 823,290	$ 751,749
Gain on the sale of assets	3,540	203	(1,622)	139	(1,514)	67	10,176	67,913	2,260	76,642	10,413
Other	2,686	442	(1,475)	1,390	914	(2,650)	1,300	506	3,043	70	(9,442)
Total revenues and other income	300,067	370,636	335,295	212,658	224,053	210,653	205,545	311,385	1,218,656	951,636	819,166
Costs and expenses:
Direct operating	25,918	29,828	28,509	28,717	27,732	25,535	21,171	21,836	112,972	96,274	98,251
Transportation, gathering and compression	34,576	32,431	28,666	25,082	20,009	15,498	14,370	12,960	120,755	62,837	37,185
Production and ad valorem taxes	5,920	7,317	7,550	6,879	6,999	6,903	5,663	6,542	27,666	26,107	25,536
Exploration	24,982	17,606	11,592	27,187	16,722	15,225	14,420	14,139	81,367	60,506	44,276
Abandonment and impairment of unproved properties	27,639	16,627	18,900	16,537	19,025	14,435	9,727	6,551	79,703	49,738	36,935
Interest expense	34,709	34,181	31,383	24,779	25,100	23,363	21,271	20,931	125,052	90,665	75,261
Depletion, depreciation and amortization	97,092	93,619	78,294	72,216	72,888	69,730	67,813	64,807	341,221	275,238	267,148
Impairment of proved properties		38,681						6,505	38,681	6,505	930
Total costs and expenses	302,681	314,910	256,816	265,986	244,009	207,216	176,136	184,667	1,140,393	812,028	734,393
Income tax expense (benefit)
Current	636	(7)	8		(826)	(10)			637	(836)	(636)
Deferred	(425)	22,547	32,695	(19,897)	(9,823)	794	11,763	49,012	34,920	51,746	46,429
Total income tax expense	211	22,540	32,703	(19,897)	(10,649)	784	11,763	49,012	35,557	50,910	45,793
Net income (loss) from discontinued operations	$ (164)	$ 1,569	$ 5,517	$ 8,398	$ (308,412)	$ (10,821)	$ (8,594)	$ (127)	15,320	(327,954)	(92,850)
Discontinued operations [Member]
Revenues and other income:
Natural gas, NGL and oil sales									59,185	157,778	139,357
Transportation and gathering									6	35
Gain on the sale of assets									4,771	955
Other									4	32	3
Total revenues and other income									63,966	158,800	139,360
Costs and expenses:
Direct operating									10,080	35,328	34,960
Transportation, gathering and compression									5,257	8,624	14,000
Production and ad valorem taxes									1,309	7,545	6,633
Exploration									37	581	2,209
Abandonment and impairment of unproved properties										20,233	76,603
Interest expense									14,791	40,527	42,106
Depletion, depreciation and amortization									8,894	88,269	106,354
Impairment of proved properties										463,244
Total costs and expenses									40,368	664,351	282,865
Income (loss) before income taxes									23,598	(505,551)	(143,505)
Income tax expense (benefit)
Current									0
Deferred									8,278	(177,597)	(50,655)
Total income tax expense									8,278	(177,597)	(50,655)
Net income (loss) from discontinued operations									$ 15,320	$ (327,954)	$ (92,850)

Discontinued Operations (Details 1) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Composition of assets of discontinued operations:
Natural gas and oil properties, net	$ 0	$ 838,044
Transportation and field assets, net	0	684
Accounts receivable	0	30,575
Unrealized derivative gain	0	8,195
Inventory and other	0	81
Total current assets of discontinued operations	0	877,579
Composition of liabilities of discontinued operations:
Account payable	0	23,366
Accrued liabilities	653	10,871
Asset retirement obligations	0	0
Total current liabilities of discontinued operations	653	34,237
Asset retirement obligations	0	1,980
Other liabilities	0	1,921
Total long-term liabilities of discontinued operations	$ 0	$ 3,901

Income Taxes (Details)	12 Months Ended
Income Taxes (Details)	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation between the statutory federal income tax rate and our effective income tax rate
Federal statutory tax rate	35.00%	35.00%	35.00%
State	7.00%	(0.20%)	20.60%
Non-deductible executive compensation	3.50%	0.20%
Valuation allowance	(0.40%)	1.40%	(1.90%)
Other	0.30%	0.10%	0.30%
Consolidated effective tax rate	45.40%	36.50%	54.00%

Income Taxes (Details 1) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Income Taxes (Details 1) - USD ($) $ in Thousands	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current:
U.S. federal											$ (1,000)
U.S. state and local									$ 637	$ (836)	364
Current	$ 636	$ (7)	$ 8		$ (826)	$ (10)			637	(836)	(636)
Deferred:
U.S. federal									30,055	51,280	29,085
U.S. state and local									4,865	466	17,344
Deferred	(425)	22,547	32,695	$ (19,897)	(9,823)	794	$ 11,763	$ 49,012	34,920	51,746	46,429
Total income tax expense	$ 211	$ 22,540	$ 32,703	$ (19,897)	$ (10,649)	$ 784	$ 11,763	$ 49,012	$ 35,557	$ 50,910	$ 45,793

- Definition

The component of income tax expense for the period representing amounts paid or payable (or refundable) as determined by applying the provisions of enacted federal tax law to the domestic taxable Income or Loss from continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 109
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher SEC
-Name Regulation S-X (SX)
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+ Details

- Definition

The component of income tax expense for the period representing amounts of income taxes paid or payable (or refundable) for the period for all income tax obligations as determined by applying the provisions of relevant enacted tax laws to relevant amounts of taxable Income or Loss from continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
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+ Details

- Definition

The component of income tax expense for the period representing amounts paid or payable (or refundable) as determined by applying the provisions of enacted state and local tax law to relevant amounts of taxable Income or Loss from continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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+ Details

- Definition

The component of total income tax expense for the period comprised of the increase (decrease) during the period in the entity's domestic deferred tax assets and liabilities attributable to continuing operations as determined by applying the provisions of the federally enacted tax law.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
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+ Details

- Definition

The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28
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-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

+ Details

- Definition

The component of total income tax expense for the period comprised of the increase (decrease) in the entity's state and local deferred tax assets and liabilities attributable to continuing operations as determined by applying the provisions of the applicable enacted tax laws.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 8, 16, 17, 289
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Income Taxes (Details 2) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Current
Deferred compensation	$ 8,607	$ 5,857
Current portion of asset retirement obligation	2,011	1,579
Other	1,423	4,106
Current portion of net operating loss carryforward	0	17,586
Total current	12,041	29,128
Non-current
Net operating loss carryforward	63,568	85,120
Deferred compensation	64,176	49,933
AMT credits and other credits	3,505	3,211
Non-current portion of asset retirement obligation	30,358	23,127
Cumulative unrealized mark-to-market loss	2,373	9,826
Other	22,076	23,481
Valuation allowance	(4,534)	(4,841)
Total non-current	181,522	189,857
Current
Net unrealized gain in AOCI related to hedge derivatives	(68,636)	(40,976)
Total current	(68,636)	(40,976)
Non-current
Depreciation, depletion and investments	(862,597)	(858,502)
Net unrealized gain in AOCI related to hedge derivatives	(29,415)	(2,616)
Other	0	(780)
Total non-current	(892,012)	(861,898)
Net deferred tax liability	$ (767,085)	$ (683,889)

Income Taxes (Details Textual) - USD ($)	12 Months Ended
Income Taxes (Details Textual) - USD ($)	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes (Textual) [Abstract]
Income tax expense from continuing operations	$ 35,600,000	$ 50,900,000	$ 45,800,000
Deferred tax liabilities exceeded deferred tax assets	(767,085,000)	(683,889,000)
Deferred tax liability related to net deferred hedging gains included in AOCI	98,100,000
Valuation allowance on the deferred compensation plan	4,500,000	$ 4,800,000
Deductible limit	1,000,000
Regular net operating loss carryforwards	299,000,000
Alternative minimum tax carryforwards	$ 261,300,000
Period during which net operating loss carryforwards and alternative minimum tax expire	2012 and 2031
Deferred tax asset related to regular NOL carryforwards net of Stock Compensation reduction for unrealized benefits	$ 32,600,000
AMT credit carryforwards that are not subject to limitation or expiration	665,000
Accrued interest or penalties related to tax amounts	0
Expected federal taxable income	$ 50,000,000

Income (Loss) Per Common Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Computations of basic and diluted (loss) income per common share
Net income (loss)	$ (2,989)	$ 34,755	$ 51,293	$ (25,033)	$ (317,719)	$ (8,168)	$ 9,052	$ 77,579	$ 58,026	$ (239,256)	$ (53,870)
Participating basic earnings									(1,037)	(454)
Basic income (loss) attributed to common stockholders									56,989	(239,710)	(53,870)
Reallocation of participating earnings									5
Diluted income (loss) attributed to common stockholders									$ 56,994	$ (239,710)	$ (53,870)
Income (loss) per common share:
Basic	$ (0.02)	$ 0.22	$ 0.32	$ (0.16)	$ (2.02)	$ (0.05)	$ 0.06	$ 0.49	$ 0.36	$ (1.53)	$ (0.35)
Diluted	$ (0.02)	$ 0.21	$ 0.32	$ (0.16)	$ (2.02)	$ (0.05)	$ 0.06	$ 0.48	$ 0.36	$ (1.52)	$ (0.34)
Denominator:
Weighted average common shares outstanding - basic									158,030	156,874	154,514
Effect of dilutive securities:
Director and employee stock options and SARs									1,411	1,554	4,264
Weighted average common shares outstanding - diluted									159,441	158,428	158,778
Continuing operations [Member]
Computations of basic and diluted (loss) income per common share
Net income (loss)									$ 42,706	$ 88,698	$ 38,980
Participating basic earnings									(763)	(1,574)
Basic income (loss) attributed to common stockholders									41,943	87,124	38,980
Reallocation of participating earnings									3	11
Diluted income (loss) attributed to common stockholders									$ 41,946	$ 87,135	$ 38,980
Income (loss) per common share:
Basic									$ 0.26	$ 0.56	$ 0.25
Diluted									$ 0.26	$ 0.55	$ 0.24
Discontinued operations [Member]
Computations of basic and diluted (loss) income per common share
Net income (loss)									$ 15,320	$ (327,954)	$ (92,850)
Participating basic earnings									(274)	1,120
Basic income (loss) attributed to common stockholders									15,046	(326,834)	(92,850)
Reallocation of participating earnings									2	(11)
Diluted income (loss) attributed to common stockholders									$ 15,048	$ (326,845)	$ (92,850)
Income (loss) per common share:
Basic									$ 0.10	$ (2.09)	$ (0.60)
Diluted									$ 0.10	$ (2.07)	$ (0.58)

Income (Loss) Per Common Share (Details Textual) - shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income from Continuing Operations Per Common Share (Textual) [Abstract]
Weighted Average Number of Shares, Restricted Stock Liability Awards	2,900,000	2,800,000	2,600,000
Stock appreciation rights excluded from earning per share calculation	795,000	2,100,000	1,100,000

- Definition

Securities (including those issuable pursuant to contingent stock agreements) that could potentially dilute basic earnings per share (EPS) or earnings per unit (EPU) in the future that were not included in the computation of diluted EPS or EPU because to do so would increase EPS or EPU amounts or decrease loss per share or unit amounts for the period presented.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 13, 14
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 40
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Diluted Earnings Per Share
-URI http://asc.fasb.org/extlink&oid=6510752

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Contingent Stock Agreement
-URI http://asc.fasb.org/extlink&oid=6508534

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Antidilution
-URI http://asc.fasb.org/extlink&oid=6505113

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Suspended Exploratory Well Costs (Details) $ in Thousands	12 Months Ended
Suspended Exploratory Well Costs (Details) $ in Thousands	Dec. 31, 2011 USD ($) Project	Dec. 31, 2010 USD ($) Project	Dec. 31, 2009 USD ($) Project
Suspended Exploratory Well Costs
Balance at beginning of period	$ 23,908	$ 19,052	$ 47,623
Additions to capitalized exploratory well costs pending the determination of proved reserves	86,996	28,897	26,216
Reclassifications to wells, facilities and equipment based on determination of proved reserves	(17,516)	(24,041)	(52,849)
Capitalized exploratory well costs charged to expense			(1,938)
Balance at end of period	93,388	23,908	19,052
Less exploratory well costs that have been capitalized for a period of one year or less	(83,860)	(13,181)	(10,778)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 9,528	$ 10,727	$ 8,274
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| Project	3	4	6

Suspended Exploratory Well Costs (Detalis 1) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for more than one year	$ 9,528	$ 10,727	$ 8,274
Exploratory well costs capitalized in year 2011 [Member]
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for more than one year	414
Exploratory well costs capitalized in year 2010 [Member]
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for more than one year	4,707
Exploratory well costs capitalized in year 2009 [Member]
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for more than one year	2,884
Exploratory well costs capitalized in year 2008 [Member]
Aging of capitalized exploratory well costs that have been suspended for more than one year
Capitalized exploratory well costs that have been capitalized for more than one year	$ 1,523

Suspended Exploratory Well Costs (Details Textual) $ in Thousands	Dec. 31, 2011 USD ($) Well	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Suspended Exploratory Well Costs (Textual) [Abstract]
Capitalized exploratory well costs that have been capitalized for more than one year \| $	$ 9,528	$ 10,727	$ 8,274
Number of Marcellus Shale wells \| Well	3

Indebtedness (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Indebtedness
Bank debt	$ 187,000	$ 274,000
Subordinated debt:
Subordinated debt	1,787,967	1,686,536
Total debt	1,974,967	1,960,536
6.375% Senior Subordinated notes due 2015 [Member]
Subordinated debt:
Subordinated debt	0	150,000
7.5% senior subordinated notes due 2016, net of discount [Member]
Subordinated debt:
Subordinated debt	0	249,683
7.5% Senior Subordinated notes due 2017 [Member]
Subordinated debt:
Subordinated debt	250,000	250,000
7.25% Senior Subordinated notes due 2018 [Member]
Subordinated debt:
Subordinated debt	250,000	250,000
8.0% Senior Subordinated notes due 2019, net of discount [Member]
Subordinated debt:
Subordinated debt	287,967	286,853
6.75% Senior Subordinated notes due 2020 [Member]
Subordinated debt:
Subordinated debt	500,000	500,000
5.75% Senior Subordinated notes due 2021 [Member]
Subordinated debt:
Subordinated debt	$ 500,000	$ 0

Indebtedness (Details 1) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Schedule for the long-term debt outstanding
2012	$ 0
2013	0
2014	0
2015	0
2016	187,000
2017	250,000
Thereafter	1,537,967
Total debt	$ 1,974,967	$ 1,960,536

Indebtedness (Details Textual) $ in Thousands	1 Months Ended	3 Months Ended			12 Months Ended
Indebtedness (Details Textual) $ in Thousands	May 31, 2011 USD ($)	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Sep. 30, 2010 USD ($)	Dec. 31, 2011 USD ($) CommercialBank	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Jun. 01, 2019	Jun. 01, 2016	Jun. 24, 2011 USD ($)	May 25, 2011 USD ($)
Debt Instrument [Line Items]
Interest costs, capitalized during period					$ 0	$ 0	$ 0
Bank debt					2.20%
Net proceeds after underwriting discounts and commissions					$ 500,000	500,000	$ 285,201
Repayment of subordinate debt					$ 413,697	202,458
Purchase price of senior subordinate notes as a percentage of principal					101.00%
Loss on early extinguishment of debt		$ (4)	$ 18,580	$ 5,351	$ 18,576	5,351
Indebtedness (Textual) [Abstract]
Bank Credit facility, Borrowing base					2,000,000
Bank Credit Facility Amount					$ 1,500,000
Number of commercial banks included in current bank group \| CommercialBank					26
Percentage holding of commercial banks, Maximum					7.00%
Notice period for increase in facility amount					20 days
Outstanding balance under the bank credit facility					$ 187,000	$ 274,000
Undrawn letters of credit					$ 28,600
Maturity date of loan					Feb. 18, 2016
Borrowing capacity available under the facility amount					$ 1,300,000
Weighted average interest rate on the bank credit facility					2.20%	2.20%	2.40%
Commitment Fee Rate					0.375%
Interest rate margin on LIBOR loans					1.50%
Interest rate margin on base rate loans					0.50%
Ratio of debt to EBITDAX					4.25
Current ratio					1.0
Maximum [Member]
Line of Credit Facility [Line Items]
Spread for Alternate Base Rate					1.50%
Spread for LIBOR Rate					2.50%
Annual rate of commitment fee paid on the undrawn balance					0.50%
Minimum [Member]
Line of Credit Facility [Line Items]
Spread for Alternate Base Rate					0.50%
Spread for LIBOR Rate					1.50%
Annual rate of commitment fee paid on the undrawn balance					0.375%
5.75 % Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount					105.75%			100.00%	102.875%
Maximum percentage of original aggregate amount of notes that can be redeemed					35.00%
Minimum percentage of original aggregate principal amount of notes to remain outstanding immediately after redemption					65.00%
Maximum number of days after the date of the closing of the equity offering that the redemption should occur					60 days
6.375% Senior Subordinated notes due 2015 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes					6.375%	6.375%
Aggregate principal amount of senior subordinated notes	$ 150,000
Repayment of subordinate debt					$ 112,900
Purchase price of senior subordinate notes as a percentage of principal										102.125%	102.375%
Purchase price of senior subordinate notes										$ 41,100	$ 108,900
7.5% senior subordinated notes due 2016, net of discount [Member]
Debt Instrument [Line Items]
Discount on Senior Subordinated notes						$ 317
Interest rate on senior subordinated notes					7.50%
Aggregate principal amount of senior subordinated notes	250,000
Repayment of subordinate debt					$ 207,100
Purchase price of senior subordinate notes as a percentage of principal										103.75%	104.00%
Purchase price of senior subordinate notes										$ 51,200	$ 198,800
7.5% Senior Subordinated notes due 2017 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes					7.50%
7.25% Senior Subordinated notes due 2018 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes					7.25%	7.25%
8.0% Senior Subordinated notes due 2019, net of discount [Member]
Debt Instrument [Line Items]
Discount on Senior Subordinated notes					$ 12,033	$ 13,147
Interest rate on senior subordinated notes					8.00%	8.00%
7.375% Senior Subordinated Notes due 2013 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes					7.375%
6.75% Senior Subordinated notes due 2020 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes					6.75%	6.75%
5.75% Senior Subordinated notes due 2021 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes					5.75%
Aggregate principal amount of senior subordinated notes	500,000
Net proceeds after underwriting discounts and commissions	$ 491,300

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligations
Beginning of period - continuing operations	$ 60,693	$ 76,589
Liabilities incurred	3,265	1,495
Acquisitions-continuing operations		556
Liabilities settled	(4,717)	(2,331)
Disposition of wells	(716)	(12,891)
Accretion expense - continuing operations	5,488	5,137
Change in estimate	20,797	(7,862)
End of period - continuing operations	84,810	60,693
Less current portion	(5,005)	(4,020)
Long-term asset retirement obligations continuing operations	79,805	56,673
Asset retirement obligations-discontinued operations	$ 0	$ 1,980

Capital Stock (Details) - shares	12 Months Ended
Capital Stock (Details) - shares	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Capital Stock
Beginning balance	159,909,052	158,118,937	155,375,487
Shares issued in lieu of cash bonuses			184,926
Stock options/SARs exercised	862,774	991,988	1,384,861
Restricted stock grants	326,591	405,127	413,353
Issued for acreage purchases		380,229	743,737
Treasury shares	33,130	12,771	16,573
Ending balance	161,131,547	159,909,052	158,118,937

- Definition

Number of shares of stock issued during the period pursuant to acquisitions.

+ References + Details

Capital Stock (Details Textual) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	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, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Capital Stock (Textual) [Abstract]
Authorized capital stock	485,000,000												485,000,000
Common stock, shares authorized	475,000,000				475,000,000								475,000,000	475,000,000
Preferred stock, shares authorized	10,000,000				10,000,000								10,000,000	10,000,000
Repurchase of common stock, approved total																$ 10.0
Repurchases of common stock, Share																78,400
Average purchase price per common stock																$ 41.11
Repurchases of common stock, Value																$ 3.2
Remaining common stock, under authorization													$ 6.8
Registration statement issued to sell shares											$ 200.0
Remaining amount in the Registration statement	$ 156.4												$ 156.4
Common stock dividends declared per share	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.04	$ 0.16	$ 0.16	$ 0.16

Derivative Activities (Details) MMBbls in Millions	Dec. 31, 2011 BblsPerDay Bcf MMBbls MmbtuPerDay PerBarrel MMBTU USD ($)
Natural Gas [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| Bcf	66.8
Average hedge price \| MMBTU	4.06
Swap NGLs (Natural Gasoline) [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| MMBbls	6.6
Average hedge price \| PerBarrel	93.30
Collars [Member] \| Crude Oil 2012 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	2,000
Average floor price	70.00
Average cap price	80.00
Collars [Member] \| Crude Oil 2013 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	3,000
Average floor price	90.60
Average cap price	100.00
Collars [Member] \| Crude Oil 2014 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	2,000
Average floor price	85.55
Average cap price	100.00
Collars [Member] \| Natural Gas 2012 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| MmbtuPerDay	234,887
Average floor price	4.99
Average cap price	5.50
Collars [Member] \| Natural Gas 2013 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| MmbtuPerDay	240,000
Average floor price	4.73
Average cap price	5.20
Collars [Member] \| Natural Gas 2014 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| MmbtuPerDay	90,000
Average floor price \| MmbtuPerDay	4.25
Average cap price	4.85
Swap [Member] \| Crude Oil 2013 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	3,000
Average hedge price	95.55
Swap [Member] \| Crude Oil 2014 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	2,000
Average hedge price	92.75
Swap [Member] \| Natural Gas 2012 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| MmbtuPerDay	182,986
Average hedge price	4.06
Swap [Member] \| NGL 2012 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	12,000
Average hedge price	96.28
Swap [Member] \| NGL 2013 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	6,000
Average hedge price	87.33
Call Option [Member] \| Crude Oil 2012 [Member]
Derivative volumes hedged and average hedge prices
Volume hedged \| BblsPerDay	4,700
Average price of oil call option (per barrel)	85.00

Derivative Activities (Details 1) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Derivative Activities (Details 1) - USD ($) $ in Thousands	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative Fair Value Income
Change in fair value of derivatives that do not qualify for hedge accounting									$ 15,762	$ (2,086)	$ (115,909)
Realized gain (loss) on settlement-natural gas									14,743	35,988	171,998
Realized gain (loss) on settlement-oil									(9,574)		7,304
Realized gain (loss) on settlement - NGL									9,612
Realized gain on early settlement of oil derivatives										15,697
Hedge ineffectiveness-realized									7,361	(352)	4,749
Hedge ineffectiveness-unrealized									2,183	2,387	(1,696)
Derivative fair value (loss) income	$ (37,879)	$ 65,761	$ 53,039	$ (40,834)	$ (7,226)	$ 9,981	$ 6,546	$ 42,333	$ 40,087	$ 51,634	$ 66,446

Derivative Activities (Details 2) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	$ 251,500	$ 131,450
Derivative liabilities:
Derivative Liabilities - Commodity collars, swaps, basis swaps and call options	(173)	(13,764)
Natural Gas [Member] \| Swap [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	54,162	0
Natural Gas [Member] \| Collars [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	228,228	155,159
Derivative liabilities:
Derivative Liabilities - Commodity collars, swaps, basis swaps and call options	0	27,032
Natural Gas [Member] \| Collars discontinued operations [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	0	8,195
Natural Gas [Member] \| Basis Swap [Member]
Derivative liabilities:
Derivative Liabilities - Commodity collars, swaps, basis swaps and call options	0	(352)
Crude Oil [Member] \| Swap [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	(263)	0
Crude Oil [Member] \| Collars [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	(16,607)	0
Derivative liabilities:
Derivative Liabilities - Commodity collars, swaps, basis swaps and call options	0	(12,051)
Crude Oil [Member] \| Call Option [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	(29,348)	(31,904)
Derivative liabilities:
Derivative Liabilities - Commodity collars, swaps, basis swaps and call options	0	(28,393)
Swap NGLs (Natural Gasoline) [Member] \| Swap [Member]
Derivative assets:
Derivative Assets - Commodity collars, swaps, basis swaps and call options	15,328	0
Derivative liabilities:
Derivative Liabilities - Commodity collars, swaps, basis swaps and call options	$ (173)	$ 0

Derivative Activities (Details 3) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Derivatives that qualify for cash flow hedge accounting :
Assets Carrying Value	$ 282,546	$ 173,128
Liabilities Carrying Value	(2,373)	0
Net Carrying Value	280,173	173,128
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	17,949	17,259
Liabilities Carrying Value	(46,795)	(72,701)
Net Carrying Value	(28,846)	(55,442)
Swap [Member]
Derivatives that qualify for cash flow hedge accounting :
Assets Carrying Value	54,318	0
Liabilities Carrying Value	(419)	0
Net Carrying Value	53,899	0
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	17,949	0
Liabilities Carrying Value	(2,794)	0
Net Carrying Value	15,155	0
Collars [Member]
Derivatives that qualify for cash flow hedge accounting :
Assets Carrying Value	228,228	164,933
Liabilities Carrying Value	(1,954)	0
Net Carrying Value	226,274	164,933
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	0	17,259
Liabilities Carrying Value	(14,653)	(12,052)
Net Carrying Value	(14,653)	5,207
Collars discontinued operations [Member]
Derivatives that qualify for cash flow hedge accounting :
Assets Carrying Value	0	8,195
Liabilities Carrying Value	0	0
Net Carrying Value	0	8,195
Call Option [Member]
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	0	0
Liabilities Carrying Value	(29,348)	(60,297)
Net Carrying Value	(29,348)	(60,297)
Basis Swap [Member]
Derivatives that do not qualify for hedge accounting :
Assets Carrying Value	0	0
Liabilities Carrying Value	0	(352)
Net Carrying Value	$ 0	$ (352)

Derivative Activities (Details 4) - USD ($) $ in Thousands	12 Months Ended
Derivative Activities (Details 4) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Effects of cash flow hedges and other hedges on accumulated other comprehensive income (loss)
Change in Hedge Derivative Fair Value	$ 275,817	$ 165,642	$ 91,059
Change in unrealized deferred hedging gains, Tax Effect	(104,464)	(64,662)	(34,180)
Change in Hedge Derivative Fair Value, effects of cash flow hedges on accumulated other comprehensive income (loss), total	171,353	100,980	56,879
Realized Gain (Loss) Reclassified from AOCI into Revenue	132,201	64,772	203,119
Realized Gain (Loss) Reclassified from AOCI into Revenue, Income taxes	(50,005)	(24,841)	(75,154)
Realized gain on hedge derivative contract settlements reclassified into earnings from other comprehensive income, net of taxes	82,196	39,931	$ 127,965
Swap [Member]
Effects of cash flow hedges and other hedges on accumulated other comprehensive income (loss)
Change in Hedge Derivative Fair Value	51,997
Collars [Member]
Effects of cash flow hedges and other hedges on accumulated other comprehensive income (loss)
Change in Hedge Derivative Fair Value	223,408	157,447
Realized Gain (Loss) Reclassified from AOCI into Revenue	123,594	64,772
Collars discontinued operations [Member]
Effects of cash flow hedges and other hedges on accumulated other comprehensive income (loss)
Change in Hedge Derivative Fair Value	412	$ 8,195
Realized Gain (Loss) Reclassified from AOCI into Revenue	$ 8,607

Derivative Activities (Details 5) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
Derivative Activities (Details 5) - USD ($) $ in Thousands	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									$ 30,543	$ 49,599	$ 63,393
Gain Recognized in Income (Ineffective Portion)									9,544	2,035	3,053
Derivative fair value (loss) income	$ (37,879)	$ 65,761	$ 53,039	$ (40,834)	$ (7,226)	$ 9,981	$ 6,546	$ 42,333	40,087	51,634	66,446
Swap [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									24,767		63,755
Gain Recognized in Income (Ineffective Portion)									0
Derivative fair value (loss) income									24,767		63,755
Collars [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									5,266	65,996	33,859
Gain Recognized in Income (Ineffective Portion)									9,544	2,035	3,053
Derivative fair value (loss) income									14,810	68,031	36,912
Call Option [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									553	(15,895)
Gain Recognized in Income (Ineffective Portion)									0
Derivative fair value (loss) income									553	(15,895)
Basis Swap [Member]
Effects of non-hedge derivatives on consolidated statement of operations
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									(43)	(502)	(34,221)
Gain Recognized in Income (Ineffective Portion)									0
Derivative fair value (loss) income									$ (43)	$ (502)	$ (34,221)

Derivative Activities (Details Textual) MMBbls in Millions	12 Months Ended
Derivative Activities (Details Textual) MMBbls in Millions	Dec. 31, 2011 USD ($) Bcf MMBbls PerBarrel MMBTU Financial_Institutions	Dec. 31, 2011 USD ($) Bcf MMBbls PerBarrel MMBTU Counterparties	Dec. 31, 2011 USD ($) Bcf MMBbls PerBarrel MMBTU	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Derivative Activities (Textual) [Abstract]
Derivative assets liabilities at fair value net	$ 251,300,000	$ 251,300,000	$ 251,300,000
Unrealized pre-tax derivative gain			254,700,000
Gains (Losses) in oil and gas sales related to settled hedging transactions			123,600,000	$ 64,800,000	$ 202,900,000
Ineffective unrealized and realized gains (losses) recognized income			$ 9,544,000	$ 2,035,000	$ 3,053,000
Number of financial institutions with whom we conduct derivative activities \| Financial_Institutions	11
Number of counter parties not included in bank credit facility	2	2
Collar Oil [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivatives \| MMBbls	2.6	2.6	2.6
Average floor price \| PerBarrel	83.26	83.26	83.26
Average cap price \| PerBarrel	94.28	94.28	94.28
Collars Gas [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivatives \| Bcf	206.4	206.4	206.4
Average floor price \| MMBTU	4.76	4.76	4.76
Average cap price \| MMBTU	5.27	5.27	5.27
Call Option Oil [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivatives \| MMBbls	1.7	1.7	1.7
Average price of oil call option (per barrel)	85.00	85.00	85.00
Swap Oil [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivatives \| MMBbls	1.8	1.8	1.8
Average price of SWAP per MCF \| PerBarrel	94.43	94.43	94.43
2012 [Member]
Derivative [Line Items]
Unrealized pre-tax derivative gain expected to be reclassified into earnings			$ 177,600,000
2013 [Member]
Derivative [Line Items]
Unrealized pre-tax derivative gain expected to be reclassified into earnings			73,500,000
2014 [Member]
Derivative [Line Items]
Unrealized pre-tax derivative gain expected to be reclassified into earnings			$ 3,500,000
Swap Natural Gas [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivatives \| Bcf	66.8	66.8	66.8
Average price of SWAP per MCF \| MMBTU	4.06	4.06	4.06
Swap NGLs (Natural Gasoline) [Member]
Derivative [Line Items]
Nonmonetary notional amount of price risk derivatives \| MMBbls	6.6	6.6	6.6
Average price of SWAP per MCF \| PerBarrel	93.30	93.30	93.30

Fair Value Measurements (Details 1) - Fair Value, Measurements, Nonrecurring [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Values of assets measured at fair value on a nonrecurring basis
Equity investments, fair value	$ 0	$ 0	$ 2,895
Equity investments, Impairment	0	0	8,950
Continuing operations [Member]
Values of assets measured at fair value on a nonrecurring basis
Natural gas and oil properties, fair value	24,388	16,075	1,244
Natural gas and oil properties, impairment	38,681	6,505	930
Discontinued operations [Member]
Values of assets measured at fair value on a nonrecurring basis
Natural gas and oil properties, fair value	0	835,913	0
Natural gas and oil properties, impairment	$ 0	$ 463,244	$ 0

- Definition

The aggregate amount of write-downs for impairments recognized during the period for long lived assets held for use (including those held for disposal by means other than sale).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
-Paragraph 26
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 144
-Paragraph 7, 25
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 45
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6390789&loc=d3e2420-110228

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6391110&loc=d3e2921-110230

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 958
-SubTopic 225
-Section 45
-Paragraph 11
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6743430&loc=d3e92212-112881

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Impairment
-URI http://asc.fasb.org/extlink&oid=6515133

+ Details

Fair Value Measurements (Details 2) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Assets
Commodity swaps, collars and call options	$ 251,500	$ 131,450
Marketable securities	50,200
Liabilities
Commodity swaps, collars, call options and basis swaps	(173)	(13,764)
Bank debt	187,000	274,000
Subordinated debt	1,787,967	1,686,536
Carrying Value [Member]
Assets
Commodity swaps, collars and call options	251,500	123,255
Commodity collars - discontinued operations	0	8,195
Marketable securities	50,237	47,794
Liabilities
Commodity swaps, collars, call options and basis swaps	(173)	(13,764)
Bank debt	(187,000)	(274,000)
Fair Value [Member]
Assets
Commodity swaps, collars and call options	251,500	123,255
Commodity collars - discontinued operations	0	8,195
Marketable securities	50,237	47,794
Liabilities
Commodity swaps, collars, call options and basis swaps	(173)	(13,764)
Bank debt	(187,000)	(274,000)
5.75% Senior Subordinated Notes due 2021 [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	(500,000)	0
5.75% Senior Subordinated Notes due 2021 [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	(541,250)	0
6.375% Senior Subordinated notes due 2015 [Member]
Liabilities
Subordinated debt	0	150,000
6.375% Senior Subordinated notes due 2015 [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	0	(150,000)
6.375% Senior Subordinated notes due 2015 [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	0	(153,000)
7.5% senior subordinated notes due 2016, net of discount [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	0	(249,683)
7.5% senior subordinated notes due 2016, net of discount [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	0	(259,375)
7.5% Senior Subordinated Notes due 2017 [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	(250,000)	(250,000)
7.5% Senior Subordinated Notes due 2017 [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	(265,625)	(263,438)
7.25% Senior Subordinated notes due 2018 [Member]
Liabilities
Subordinated debt	250,000	250,000
7.25% Senior Subordinated notes due 2018 [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	(250,000)	(250,000)
7.25% Senior Subordinated notes due 2018 [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	(267,500)	(263,750)
8.0% Senior Subordinated notes due 2019, net of discount [Member]
Liabilities
Subordinated debt	287,967	286,853
8.0% Senior Subordinated notes due 2019, net of discount [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	(287,967)	(286,853)
8.0% Senior Subordinated notes due 2019, net of discount [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	(334,500)	(326,625)
6.75% Senior Subordinated notes due 2020 [Member]
Liabilities
Subordinated debt	500,000	500,000
6.75% Senior Subordinated notes due 2020 [Member] \| Carrying Value [Member]
Liabilities
Subordinated debt	(500,000)	(500,000)
6.75% Senior Subordinated notes due 2020 [Member] \| Fair Value [Member]
Liabilities
Subordinated debt	$ (555,000)	$ (515,625)

Fair Value Measurements (Details Textual)	3 Months Ended		12 Months Ended
Fair Value Measurements (Details Textual)	Sep. 30, 2011 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2011 USD ($) Financial_Institutions	Dec. 31, 2011 USD ($) Counterparties	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties	$ 38,681,000	$ 6,505,000			$ 38,681,000	$ 6,505,000	$ 930,000
Fair Value Measurements (Textual) [Abstract]
Interest and dividends					1,400,000	864,000	487,000
Mark-to-market gain (loss)					(2,300,000)	11,500,000	10,400,000
Allowance for uncollectible receivables			$ 4,000,000	$ 4,000,000	4,000,000	5,000,000
Net derivative receivable			$ 9,600,000	$ 9,600,000	9,600,000
Number of financial institutions included in counterparties \| Financial_Institutions			11
Number of counter parties not included in bank credit facility			2	2
Discontinued operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties						463,244,000
Whipstock Natural Gas Services LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity investments, Impairment							9,000,000
Fair Value, Measurements, Nonrecurring [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity investments, Impairment					$ 0	0	8,950,000
Fair Value, Measurements, Nonrecurring [Member] \| Discontinued operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties						$ 463,244,000
6.375% Senior Subordinated notes due 2015 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			6.375%	6.375%	6.375%	6.375%
7.5% senior subordinated notes due 2016, net of discount [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			7.50%	7.50%	7.50%	7.50%
7.5% Senior Subordinated Notes due 2017 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			7.50%	7.50%	7.50%	7.50%
7.25% Senior Subordinated notes due 2018 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			7.25%	7.25%	7.25%	7.25%
8.0% Senior Subordinated notes due 2019, net of discount [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			8.00%	8.00%	8.00%	8.00%
6.75% Senior Subordinated notes due 2020 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			6.75%	6.75%	6.75%	6.75%
5.75% Senior Subordinated Notes due 2021 [Member]
Debt Instrument [Line Items]
Interest rate on senior subordinated notes			5.75%	5.75%	5.75%	5.75%
East Texas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties	$ 31,200,000				$ 31,200,000
Gulf Coast [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties					$ 7,500,000	$ 6,500,000
Michigan [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Oil and Gas Properties							$ 930,000

Stock Based Compensation Plans (Details) - $ / shares	12 Months Ended
Stock Based Compensation Plans (Details) - $ / shares	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Stock option and SARs activities
Beginning Balance, Shares	6,461,839	7,154,712	7,248,666
Beginning Balance, Weighted Average Exercise Price	$ 37.20	$ 31.38	$ 26.15
Granted	$ 51.17	$ 46.09	$ 36.90
Granted, Shares	843,485	1,394,136	1,714,165
Exercised	$ 32.69	$ 20.49	$ 14.31
Exercised, Shares	(2,511,989)	(1,883,091)	(1,717,584)
Expired/forfeited	$ 52.65	$ 48.18	$ 40.73
Expired/forfeited, Shares	(234,726)	(203,918)	(90,535)
Ending Balance, Shares	4,558,609	6,461,839	7,154,712
Ending Balance, Weighted Average Exercise Price	$ 41.47	$ 37.20	$ 31.38

Stock Based Compensation Plans (Details 1)	12 Months Ended
Stock Based Compensation Plans (Details 1)	Dec. 31, 2011 yr $ / shares shares	Dec. 31, 2010 $ / shares	Dec. 31, 2009 $ / shares	Dec. 31, 2008 $ / shares
Outstanding stock options and SARs
Number of outstanding options and SARs \| shares	4,558,609
Weighted Average Remaining Contractual Life (in years) \| yr	2.35
Weighted-Average Exercise Price	$ 41.47	$ 37.20	$ 31.38	$ 26.15
Number of exercisable options and SARs \| shares	2,438,136
Weighted-Average Exercise Price	$ 37.66
Range of Exercise Prices One [Member]
Outstanding stock options and SARs
Exercise price, Minimum	1.29
Exercise price, Maximum	$ 9.99
Number of outstanding options and SARs \| shares	619,716
Weighted Average Remaining Contractual Life (in years) \| yr	0.29
Weighted-Average Exercise Price	$ 3.41
Number of exercisable options and SARs \| shares	619,716
Weighted-Average Exercise Price	$ 3.41
Range of Exercise Prices Two [Member]
Outstanding stock options and SARs
Exercise price, Minimum	10.00
Exercise price, Maximum	$ 19.99
Number of outstanding options and SARs \| shares	15,435
Weighted Average Remaining Contractual Life (in years) \| yr	3.73
Weighted-Average Exercise Price	$ 19.63
Number of exercisable options and SARs \| shares	15,435
Weighted-Average Exercise Price	$ 19.63
Range of Exercise Prices Three [Member]
Outstanding stock options and SARs
Exercise price, Minimum	20.00
Exercise price, Maximum	$ 29.99
Number of outstanding options and SARs \| shares	0
Weighted Average Remaining Contractual Life (in years) \| yr	0
Weighted-Average Exercise Price	$ 0
Number of exercisable options and SARs \| shares	0
Weighted-Average Exercise Price	$ 0
Range of Exercise Prices Four [Member]
Outstanding stock options and SARs
Exercise price, Minimum	30.00
Exercise price, Maximum	$ 39.99
Number of outstanding options and SARs \| shares	808,975
Weighted Average Remaining Contractual Life (in years) \| yr	1.52
Weighted-Average Exercise Price	$ 34.90
Number of exercisable options and SARs \| shares	506,868
Weighted-Average Exercise Price	$ 35.30
Range of Exercise Prices Five [Member]
Outstanding stock options and SARs
Exercise price, Minimum	40.00
Exercise price, Maximum	$ 49.99
Number of outstanding options and SARs \| shares	1,968,934
Weighted Average Remaining Contractual Life (in years) \| yr	3.12
Weighted-Average Exercise Price	$ 45.28
Number of exercisable options and SARs \| shares	643,665
Weighted-Average Exercise Price	$ 43.63
Range of Exercise Prices Six [Member]
Outstanding stock options and SARs
Exercise price, Minimum	50.00
Exercise price, Maximum	$ 59.99
Number of outstanding options and SARs \| shares	803,137
Weighted Average Remaining Contractual Life (in years) \| yr	3.29
Weighted-Average Exercise Price	$ 54.39
Number of exercisable options and SARs \| shares	310,905
Weighted-Average Exercise Price	$ 57.64
Range of Exercise Prices Seven [Member]
Outstanding stock options and SARs
Exercise price, Minimum	60.00
Exercise price, Maximum	$ 69.99
Number of outstanding options and SARs \| shares	13,542
Weighted Average Remaining Contractual Life (in years) \| yr	1.65
Weighted-Average Exercise Price	$ 66.04
Number of exercisable options and SARs \| shares	12,677
Weighted-Average Exercise Price	$ 65.91
Range of Exercise Prices Eight [Member]
Outstanding stock options and SARs
Exercise price, Minimum	70.00
Exercise price, Maximum	$ 75.00
Number of outstanding options and SARs \| shares	328,870
Weighted Average Remaining Contractual Life (in years) \| yr	1.39
Weighted-Average Exercise Price	$ 75.00
Number of exercisable options and SARs \| shares	328,870
Weighted-Average Exercise Price	$ 75.00

Stock Based Compensation Plans (Details 2)	12 Months Ended
Stock Based Compensation Plans (Details 2)	Dec. 31, 2011 yr $ / shares	Dec. 31, 2010 yr $ / shares	Dec. 31, 2009 yr $ / shares
Weighted average grant date fair value of these SARs
Weighted average exercise price per share	$ 51.17	$ 46.09	$ 36.90
Expected annual dividends per share	0.31%	0.35%	0.44%
Expected life in years \| yr	3.7	3.6	3.5
Expected volatility	47.00%	49.00%	58.00%
Risk-free interest rate	1.40%	1.60%	1.50%
Weighted average grant date fair value	$ 18.22	$ 17.01	$ 15.42

Stock Based Compensation Plans (Details 3) - $ / shares	12 Months Ended
Stock Based Compensation Plans (Details 3) - $ / shares	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restricted stock and Restricted stock units outstanding
Granted	$ 18.22	$ 17.01	$ 15.42
Equity Awards [Member]
Restricted stock and Restricted stock units outstanding
Beginning Balance, Shares	0	0	0
Beginning Balance, Weighted Average Exercise Price	$ 0.00	$ 0.00	$ 0.00
Granted	$ 49.56	$ 0.00	$ 0.00
Granted, Shares	331,209	0	0
Vested	$ 49.37	$ 0.00	$ 0.00
Vested, Shares	(88,854)	0	0
Forfeited	$ 49.45	$ 0.00	$ 0.00
Forfeited, Shares	(20,746)	0	0
Ending Balance, Shares	221,609	0	0
Ending Balance, Weighted Average Exercise Price	$ 49.64	$ 0.00	$ 0.00
Liability Awards [Member]
Restricted stock and Restricted stock units outstanding
Beginning Balance, Shares	582,751	627,189	473,547
Beginning Balance, Weighted Average Exercise Price	$ 44.81	$ 45.64	$ 48.50
Granted	$ 51.17	$ 45.83	$ 39.99
Granted, Shares	349,840	413,422	685,578
Vested	$ 45.50	$ 46.90	$ 40.91
Vested, Shares	(416,055)	(439,361)	(521,536)
Forfeited	$ 45.04	$ 46.04	$ 40.83
Forfeited, Shares	(29,292)	(18,499)	(10,400)
Ending Balance, Shares	487,244	582,751	627,189
Ending Balance, Weighted Average Exercise Price	$ 48.76	$ 44.81	$ 45.64

Stock Based Compensation Plans (Details Textual)	3 Months Ended								12 Months Ended
Stock Based Compensation Plans (Details Textual)	Dec. 31, 2011 USD ($) $ / shares shares	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2010 USD ($) shares	Sep. 30, 2010 USD ($)	Jun. 30, 2010 USD ($)	Mar. 31, 2010 USD ($)	Dec. 31, 2011 USD ($) yr Plan $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares	Dec. 31, 2008 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares Outstanding Under the Plans \| shares	4,558,609				6,461,839				4,558,609	6,461,839	7,154,712	7,248,666
Vesting period of awards									3 years
Expiration term of stock options									5
Operating expense	$ 25,918,000	$ 29,828,000	$ 28,509,000	$ 28,717,000	$ 27,732,000	$ 25,535,000	$ 21,171,000	$ 21,836,000	$ 112,972,000	$ 96,274,000	$ 98,251,000
Exploration expense	24,982,000	17,606,000	11,592,000	27,187,000	16,722,000	15,225,000	14,420,000	14,139,000	81,367,000	60,506,000	44,276,000
General and administrative expense	$ 42,205,000	$ 35,907,000	$ 39,120,000	$ 33,959,000	40,042,000	$ 36,523,000	$ 35,836,000	28,170,000	$ 151,191,000	140,571,000	115,319,000
Termination costs					$ 514,000			$ 7,938,000		8,452,000	2,479,000
Vesting period of shares granted to employees									3 years
Stock-based compensation expense									$ 4,108,000	4,209,000	4,817,000
Stock Based Compensation Plans (Textual) [Abstract]
Incremental Compensation										2,800,000	332,000
Stock-Based Compensation Expense									43,800,000	44,400,000	41,600,000
Cash received upon exercise of stock options/SARs awards									620,000
Tax benefit of stock compensation									$ 11,676,000
Active equity-based stock plans \| Plan									2
Number of stock option outstanding \| shares	635,000								635,000
Number of SARs outstanding \| shares	3,900,000								3,900,000
Total intrinsic value of stock options and SARs exercised									$ 62,500,000	50,600,000	50,900,000
Aggregate intrinsic value of the awards outstanding	$ 97,700,000								97,700,000
Aggregate intrinsic value of the awards exercisable	$ 63,600,000								$ 63,600,000
Weighted average remaining contractual life of awards exercisable \| yr									1.5
Number of fully vested awards and awards expected to vest \| shares	4,400,000								4,400,000
Weighted average remaining contractual life of fully vested awards and awards expected to vest \| yr									2.3
Weighted average exercise price of fully vested awards and awards expected to vest \| $ / shares	$ 41.32								$ 41.32
Aggregate intrinsic value of fully vested awards and awards expected to vest	$ 94,700,000								$ 94,700,000
Non-cash, Mark-to-market income (loss) related to deferred compensation plan									$ (43,200,000)	10,200,000	$ (31,100,000)
Maximum Percentage of Employees Contribution	75.00%								75.00%
Maximum percentage of employers contribution in cash									6.00%
Employer Contribution									$ 3,300,000	$ 3,100,000
Minimum period of service for contribution to fully vest									2 years
Shares held in rabbi trust total \| shares	2,800,000				2,900,000				2,800,000	2,900,000
Vested shares held in rabbi trust \| shares	2,300,000				2,300,000				2,300,000	2,300,000
Stock Appreciation Rights [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of awards									3 years
Expiration term of stock options									5
Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation of fully vested awards and awards expected to vest	$ 11,000,000								$ 11,000,000
Weighted average period \| yr									2.2
Shares granted to employees \| shares									331,000
Vesting period of shares granted to employees									3 years
Stock-based compensation expense									$ 4,200,000
Shares granted to employees and directors \| shares									331,209	0	0
1999 Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares issued Under the Plans \| shares									2,200,000
2005 Equity Based Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares issued Under the Plans \| shares									5,600,000
Maximum number of common stock authorized to be issued under the Plans \| shares	15,000,000								15,000,000
Number of Shares Outstanding Under the Plans \| shares	7,200,000								7,200,000
Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation of fully vested awards and awards expected to vest	$ 21,000,000								$ 21,000,000
Weighted average period									1.7
Shares granted to employees \| shares									334,000	392,000	663,000
Shares granted to directors \| shares									16,000	21,000	23,000
Vesting period of shares granted to employees									3 years	3 years	3 years
Restricted Stock granted average price \| $ / shares									$ 51.17	$ 45.83	$ 39.99
Compensation cost related to restricted stock grants									$ 19,100,000	$ 20,500,000	$ 19,700,000
Proceeds received from sale of stock held in deferred compensation plan									$ 12,900,000
Shares granted to employees and directors \| shares									349,840	413,422	685,578
Director Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum number of common stock authorized to be issued under the Plans \| shares	450,000								450,000
Share Based Compensation Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Operating expense									$ 2,000,000	$ 2,000,000	$ 2,500,000
Exploration expense									4,100,000	4,200,000	4,700,000
General and administrative expense									$ 36,200,000	34,200,000	33,300,000
Termination costs										$ 2,800,000	$ 332,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of awards									3 years
Stock Option and SARs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation of fully vested awards and awards expected to vest	$ 20,200,000								$ 20,200,000
Weighted average period									1.7

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net cash provided from operating activities included:
Income taxes paid (refunded from) to taxing authorities	$ 675	$ (1,359)	$ 170
Interest paid	133,103	116,766	108,685
Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net	$ 24,061	(6,370)	4,985
Unproved property purchased with stock		$ 20,000	33,726
Shares issued in lieu of bonuses			$ 6,312

Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Future minimum rental commitments
2012	$ 12,843
2013	11,648
2014	10,923
2015	10,755
2016	8,438
Thereafter	27,701
Sublease rentals	(963)
Operating Leases Future Minimum Payments Due Including Sub lease	$ 81,345

Commitments and Contingencies (Details 1) $ in Thousands	Dec. 31, 2011 USD ($)
Future minimum transportation and gathering fees
2012	$ 103,030
2013	102,693
2014	102,221
2015	99,298
2016	99,424
Thereafter	506,798
Total	$ 1,013,464

Commitments and Contingencies (Details 2)	Dec. 31, 2011 McfePerDay
Future delivery commitments
2012	1,370
2013	33,434
2014	96,174
2015	98,913
2016	99,589
Thereafter	90,000

Commitments and Contingencies (Details Textual)	12 Months Ended
Commitments and Contingencies (Details Textual)	Dec. 31, 2011 USD ($) Secured_lenders yr McfePerDay	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Commitments and Contingencies (Textual) [Abstract]
Rent expense under operating leases	$ 18,600,000	$ 18,500,000	$ 18,800,000
Number of drilling rigs used under drilling contracts \| Secured_lenders	3
Maximum period of drilling contracts in years \| yr	3
Maximum penalties on Early termination of drilling contracts	$ 22,200,000
Minimum remaining terms of leases on undeveloped acreage, in years \| yr	3
Maximum remaining terms of leases on undeveloped acreage, in years \| yr	5
2012 [Member]
Commitments And Contingencies [Line Items]
Amount of lease agreement for hydraulic fracturing services	$ 70,100,000
Drilling contracts, future minimum commitments	$ 25,000,000
Incremental increase in gas production, Mcf per day in Appalachia \| McfePerDay	143,000
Amount of agreement to purchase seismic data	$ 7,200,000
2013 [Member]
Commitments And Contingencies [Line Items]
Amount of lease agreement for hydraulic fracturing services	52,600,000
Drilling contracts, future minimum commitments	$ 14,700,000
Incremental increase in gas production, Mcf per day in Appalachia \| McfePerDay	251,900
Amount of agreement to purchase seismic data	$ 1,800,000
2014 [Member]
Commitments And Contingencies [Line Items]
Drilling contracts, future minimum commitments	$ 896,000
Incremental increase in gas production, Mcf per day in Appalachia \| McfePerDay	346,400
2015 [Member]
Commitments And Contingencies [Line Items]
Incremental increase in gas production, Mcf per day in Appalachia \| McfePerDay	363,000
2016 [Member]
Commitments And Contingencies [Line Items]
Incremental increase in gas production, Mcf per day in Appalachia \| McfePerDay	438,800
Thereafter [Member]
Commitments And Contingencies [Line Items]
Incremental increase in gas production, Mcf per day in Appalachia \| McfePerDay	443,000

Major Customers (Details) - Customer	12 Months Ended
Major Customers (Details) - Customer	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Major Customers
Number of customers accounted for more than 10% of total Oil and Gas revenues	2	0	0
Percentage of total Oil and Gas revenues accounted by customers	10.00%	10.00%	10.00%

Equity Method Investments (Details) - USD ($)	1 Months Ended	12 Months Ended
Equity Method Investments (Details) - USD ($)	May 31, 2007	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2006
Equity Method Investments (Textual) [Abstract]
Loss (gain) from equity method investments, net of distributions		$ 16,871,000	$ (7,366,000)	$ 6,693,000
Net book value of investment		$ 138,130,000	155,105,000
Whipstock Natural Gas Services LLC [Member]
Equity Method Investments (Textual) [Abstract]
Equity investments, Impairment				9,000,000
Percentage ownership interest		50.00%			50.00%
Cash contributed for investment					$ 11,700,000
Loss (gain) from equity method investments, net of distributions		$ 487,000	2,200,000	13,100,000
Cash distribution from investment				301,000
Reduction in equity to eliminate the profit from gathering and transportation fees		6,000	1,100,000	422,000
Net book value of investment		$ 1,100,000
Nora Gathering LLC [Member]
Equity Method Investments (Textual) [Abstract]
Percentage ownership interest	50.00%	50.00%
Cash contributed for investment	$ 94,700,000
Loss (gain) from equity method investments, net of distributions		$ 563,000	(684,000)	(629,600)
Cash distribution from investment		23,500,000	0	0
Reduction in equity to eliminate the profit from gathering and transportation fees		7,700,000	8,800,000	7,000,000
Net book value of investment		137,000,000
Contribution by Both Parties as Additional Capital to Fund Expansion		$ 0	$ 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, 2011	Dec. 31, 2010	Dec. 31, 2009
Exit activities included in accrued liabilities in consolidated balance sheet
Beginning Balance	$ 1,568,000			$ 1,092,000	$ 1,568,000	$ 0
Accrued one-time termination costs	$ 5,100,000	$ 635,000	$ 1,300,000	0	5,138,000	1,895,000
Office lease				0	514,000	252,000
Payments				(1,040,000)	(6,128,000)	(579,000)
Ending Balance		$ 1,568,000		$ 52,000	$ 1,092,000	$ 1,568,000

Office Closing and Exit Activities (Details Textual) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restructuring and Related Cost [Line Items]
Increasing in termination costs for stock compensation expense	$ 514,000	$ 7,938,000				$ 8,452,000	$ 2,479,000
Office Closing and Exit Activities (Textual) [Abstract]
Accrued severance costs		5,100,000	$ 635,000	$ 1,300,000	$ 0	$ 5,138,000	$ 1,895,000
Employee Severance [Member]
Restructuring and Related Cost [Line Items]
Increasing in termination costs for stock compensation expense		$ 2,800,000

- Definition

The charge against earnings in the period, comprised of costs associated with restructuring activities not otherwise specified in the taxonomy pursuant to a duly authorized plan, excluding a discontinued operation as defined by generally accepted accounting principles. Costs of such activities include those for one-time termination benefits, termination of an operating lease or other contract, consolidating or closing facilities, and relocating employees, but excludes costs associated with the retirement of a long-lived asset and severance costs associated with established compensation plans.

+ References + Details

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues and other income:
Natural gas, NGLs and oil sales	$ 331,720	$ 304,230	$ 285,353	$ 251,963	$ 231,879	$ 203,255	$ 187,523	$ 200,633	$ 1,173,266	$ 823,290	$ 751,749
Derivative fair value (loss) income	(37,879)	65,761	53,039	(40,834)	(7,226)	9,981	6,546	42,333	40,087	51,634	66,446
Gain (loss) on the sale of assets	3,540	203	(1,622)	139	(1,514)	67	10,176	67,913	2,260	76,642	10,413
Other	2,686	442	(1,475)	1,390	914	(2,650)	1,300	506	3,043	70	(9,442)
Total revenues and other income	300,067	370,636	335,295	212,658	224,053	210,653	205,545	311,385	1,218,656	951,636	819,166
Costs and expenses:
Direct operating	25,918	29,828	28,509	28,717	27,732	25,535	21,171	21,836	112,972	96,274	98,251
Transportation, gathering and compression	34,576	32,431	28,666	25,082	20,009	15,498	14,370	12,960	120,755	62,837	37,185
Production and ad valorem taxes	5,920	7,317	7,550	6,879	6,999	6,903	5,663	6,542	27,666	26,107	25,536
Exploration	24,982	17,606	11,592	27,187	16,722	15,225	14,420	14,139	81,367	60,506	44,276
Abandonment and impairment of unproved properties	27,639	16,627	18,900	16,537	19,025	14,435	9,727	6,551	79,703	49,738	36,935
General and administrative	42,205	35,907	39,120	33,959	40,042	36,523	35,836	28,170	151,191	140,571	115,319
Termination costs					514			7,938		8,452	2,479
Deferred compensation plan	9,640	8,717	(5,778)	30,630	14,978	(5,347)	(14,135)	(5,712)	43,209	(10,216)	31,073
Interest expense	34,709	34,181	31,383	24,779	25,100	23,363	21,271	20,931	125,052	90,665	75,261
Loss on early extinguishment of debt		(4)	18,580			5,351			18,576	5,351
Depletion, depreciation and amortization	97,092	93,619	78,294	72,216	72,888	69,730	67,813	64,807	341,221	275,238	267,148
Impairment of proved properties		38,681						6,505	38,681	6,505	930
Total costs and expenses	302,681	314,910	256,816	265,986	244,009	207,216	176,136	184,667	1,140,393	812,028	734,393
Income from continuing operations before income taxes	(2,614)	55,726	78,479	(53,328)	(19,956)	3,437	29,409	126,718	78,263	139,608	84,773
Income tax expense (benefit)
Current	636	(7)	8		(826)	(10)			637	(836)	(636)
Deferred	(425)	22,547	32,695	(19,897)	(9,823)	794	11,763	49,012	34,920	51,746	46,429
Total income tax (benefit) expense	211	22,540	32,703	(19,897)	(10,649)	784	11,763	49,012	35,557	50,910	45,793
Income from continuing operations	(2,825)	33,186	45,776	(33,431)	(9,307)	2,653	17,646	77,706	42,706	88,698	38,980
Discontinued operations, net of taxes	(164)	1,569	5,517	8,398	(308,412)	(10,821)	(8,594)	(127)	15,320	(327,954)	(92,850)
Net income (loss)	$ (2,989)	$ 34,755	$ 51,293	$ (25,033)	$ (317,719)	$ (8,168)	$ 9,052	$ 77,579	$ 58,026	$ (239,256)	$ (53,870)
Income (loss) per common share:
Basic-income (loss) from continuing operations	$ (0.02)	$ 0.21	$ 0.28	$ (0.21)	$ (0.06)	$ 0.02	$ 0.11	$ 0.49	$ 0.26	$ 0.56	$ 0.25
-discontinued operations		0.01	0.04	0.05	(1.96)	(0.07)	(0.05)		0.10	(2.09)	(0.6)
-net income (loss)	(0.02)	0.22	0.32	(0.16)	(2.02)	(0.05)	0.06	0.49	0.36	(1.53)	(0.35)
Diluted-income (loss) from continuing operations	(0.02)	0.20	0.28	(0.21)	(0.06)	0.02	0.11	0.48	0.26	0.55	0.24
-discontinued operations		0.01	0.04	0.05	(1.96)	(0.07)	(0.05)		0.10	(2.07)	(0.58)
-net income (loss)	$ (0.02)	$ 0.21	$ 0.32	$ (0.16)	$ (2.02)	$ (0.05)	$ 0.06	$ 0.48	$ 0.36	$ (1.52)	$ (0.34)

Selected Quarterly Financial Data (Unaudited) (Details 1) - USD ($) $ in Millions	3 Months Ended							12 Months Ended
	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	May 31, 2007	Dec. 31, 2006
Selected Quarterly Financial Data (Textual) [Abstract]
Increased natural gas, NGLs and oil sales	$ 32.4	$ 28.7	$ 25.1	$ 20.0	$ 15.5	$ 14.4	$ 13.0
Prior period adjustment for impairment expense								$ 3.0
Prior period adjustment for deferred tax expense								$ 3.1
Whipstock Natural Gas Services LLC [Member]
Principal Unconsolidated Investees [Abstract]
Percentage ownership interest								50.00%		50.00%
Drilling Services								Drilling services
Nora Gathering LLC [Member]
Principal Unconsolidated Investees [Abstract]
Percentage ownership interest								50.00%	50.00%
Gas Gathering and Transportation								Gas gathering and transportation

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Natural gas and oil properties:
Properties subject to depletion	$ 6,035,429	$ 4,742,248	$ 4,144,007
Unproved properties	748,598	648,143	572,471
Total	6,784,027	5,390,391	4,716,478
Accumulated depreciation, depletion and amortization	(1,626,461)	(1,306,378)	(1,164,843)
Net capitalized costs	$ 5,157,566	$ 4,084,013	$ 3,551,635

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Acquisitions:
Unproved leasehold		$ 3,697
Proved oil and gas properties		130,767
Asset retirement obligations		556
Acreage purchases	$ 220,576	151,572	$ 162,172
Development	1,007,049	727,720	374,970
Exploration:
Drilling	226,920	50,433	49,029
Expense	77,259	56,298	39,873
Stock-based compensation expense	4,108	4,209	4,817
Gas gathering facilities:
Development	53,387	19,627	27,937
Subtotal	1,589,299	1,144,879	658,798
Asset retirement obligations	24,061	(6,370)	4,985
Total - continuing operations	1,613,360	1,138,509	663,783
Discontinued operations	3,241	73,369	150,461
Total costs incurred	$ 1,616,601	$ 1,211,878	$ 814,244

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2011 Trillion_Cubic_Feet_Equivalents MMcf MBbls MMcfe Billions_Of_Cubic_Feet_Equivalent	Dec. 31, 2010 Trillion_Cubic_Feet_Equivalents MMcf MBbls MMcfe Billions_Of_Cubic_Feet_Equivalent	Dec. 31, 2009 MMcf MBbls MMcfe Billions_Of_Cubic_Feet_Equivalent
Proved Developed and Undeveloped Reserves [Abstract]
Revisions \| Billions_Of_Cubic_Feet_Equivalent	225	148.6	3.9
Extensions, discoveries and additions	1.5	1.4	770
Crude Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance	23,239	34,082	49,487
Revisions	6,522	(2,672)	(1,536)
Extensions, discoveries and additions	4,915	4,663	3,479
Purchases	0		0
Property sales	(1,176)	(10,865)	(14,791)
Production	(1,968)	(1,969)	(2,557)
Ending Balance	31,532	23,239	34,082
Proved developed reserves:
Proved developed reserves	17,872	17,050	20,626
Changes in proved undeveloped reserves for 2011 (Mmcfe)
Proved undeveloped reserves	13,660	6,189	13,457
Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance \| MMcf	3,566,526	2,614,717	2,213,546
Revisions \| MMcf	73,643	3,599	(37,497)
Extensions, discoveries and additions \| MMcf	1,304,324	1,089,632	620,114
Purchases \| MMcf	0	124,981	0
Property sales \| MMcf	(777,816)	(124,369)	(50,797)
Production \| MMcf	(157,001)	(142,034)	(130,649)
Ending Balance \| MMcf	4,009,676	3,566,526	2,614,717
Proved developed reserves:
Proved developed reserves \| MMcf	1,907,209	1,762,766	1,445,705
Changes in proved undeveloped reserves for 2011 (Mmcfe)
Proved undeveloped reserves \| MMcf	2,102,467	1,803,760	1,169,012
Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance	122,722	51,588	23,849
Revisions	18,627	26,832	8,434
Extensions, discoveries and additions	26,591	48,792	21,492
Purchases	0		0
Property sales	(19,852)
Production	(5,573)	(4,490)	(2,187)
Ending Balance	142,515	122,722	51,588
Proved developed reserves:
Proved developed reserves	64,472	53,071	26,205
Changes in proved undeveloped reserves for 2011 (Mmcfe)
Proved undeveloped reserves	78,043	69,651	25,382
Natural Gas Equivalents [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance \| MMcfe	4,442,290	3,128,739	2,653,565
Revisions \| MMcfe	224,542	148,558	3,890
Extensions, discoveries and additions \| MMcfe	1,493,357	1,410,359	769,939
Purchases \| MMcfe	0	124,981	0
Property sales \| MMcfe	(903,983)	(189,558)	(139,543)
Production \| MMcfe	(202,245)	(180,789)	(159,112)
Ending Balance \| MMcfe	5,053,961	4,442,290	3,128,739
Proved developed reserves:
Proved developed reserves \| MMcfe	2,401,274	2,183,488	1,726,696
Changes in proved undeveloped reserves for 2011 (Mmcfe)
Proved undeveloped reserves \| MMcfe	2,652,687	2,258,802	1,402,043

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Details 3)	12 Months Ended
	Dec. 31, 2011 MMcfe
Changes in proved undeveloped reserves for 2011 (Mmcfe)
Beginning proved undeveloped reserves-2010	2,258,802
Undeveloped reserves transferred to developed	(364,150)
Revisions	(15,098)
Purchases/sales	(408,740)
Extension and discoveries	1,181,873
Ending proved undeveloped reserves-2011	2,652,687

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future cash inflows	$ 23,954,048	$ 19,676,630
Future Costs
Production	(5,113,902)	(4,305,292)
Development	(3,230,577)	(2,855,407)
Future net cash flows before income taxes	15,609,569	12,515,931
Future income tax expense	(5,040,104)	(3,923,264)
Total future net cash flows before 10% discount	10,569,465	8,592,667
10% annual discount	(6,054,568)	(5,113,541)
Standardized measure of discounted future net cash flows	$ 4,514,897	$ 3,479,126

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Details 5) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revisions of previous estimates:
Changes in prices	$ 422,080	$ 957,994	$ (992,809)
Revisions in quantities	326,240	190,874	4,124
Changes in future development costs	(346,378)	(474,058)	(375,344)
Accretion of discount	464,735	259,280	340,025
Net change in income taxes	(400,690)	(666,517)	317,158
Purchases of reserves in place		160,580
Additions to proved reserves from extensions, discoveries and improved recovery	2,169,706	1,812,077	816,278
Production	(911,873)	(744,354)	(673,907)
Development costs incurred during the period	513,551	298,624	316,523
Sales of natural gas and oil	(1,313,401)	(243,551)	(147,942)
Timing and other	111,801	(162,912)	(94,397)
Net change for the year	1,035,771	1,388,037	(490,291)
Beginning of period	$ 3,479,126	$ 2,091,089	$ 2,581,380

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Details Textual)	12 Months Ended
	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($) Trillion_Cubic_Feet_Equivalents MMcf MBbls MMcfe Billions_Of_Cubic_Feet_Equivalent	Dec. 31, 2010 USD ($) Trillion_Cubic_Feet_Equivalents MMcf MBbls MMcfe Billions_Of_Cubic_Feet_Equivalent	Dec. 31, 2009 USD ($) MMcf MBbls Billions_Of_Cubic_Feet_Equivalent shares	Dec. 31, 2008 MMcf MBbls
Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Textual) [Abstract]
Stock Issued to Purchase acreage, Value \| $						$ 20,000,000
Stock Issued to Purchase acreage, Shares \| shares						380,229
Percentage of proved resources reviewed by consultants				89.00%
Variance in reserve estimates				less than 5%
Period for which the reserves have been reported to be included in proved undeveloped reserves				five or more years
Conversion Rate of Oil and NGLS to MCFE				one barrel equals six mcf
Undeveloped reserves transferred to developed reserves \| $				$ 374,200,000
Estimated future development costs \| $	$ 829,200,000	$ 805,300,000	$ 550,800,000
Volume of Mmcfe of reserves that have been reported for five or more years included in proved undeveloped reserves, approximately \| MMcfe				4,946
Percentage of proved undeveloped reserves				less than 1%
Discount rate applying for resulting future net cash flows				10.00%
Scheduled drilling period maximum for undeveloped reserves				scheduled to be within five years
Proved reserves from drilling activities and evaluations of proved areas				1.5	1.4	770
Reserves Attributable To Natural Gas				87.00%	77.00%	81.00%
Positive performance revisions for natural gas properties \| Billions_Of_Cubic_Feet_Equivalent					40.5	89.9
Revision of previous estimates \| Billions_Of_Cubic_Feet_Equivalent				225	148.6	3.9
Negative price revisions \| Billions_Of_Cubic_Feet_Equivalent						86.0
Discontinued Operation [Member]
Average Sales Price and Production Costs Per Unit of Production
Proved reserves \| MMcfe					906,371
Proved undeveloped reserves \| MMcfe					408,710
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 \| $				$ 95.61	$ 79.81	$ 60.85
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 \| $				4.12	4.38	3.87
Crude Oil [Member]
Average Sales Price and Production Costs Per Unit of Production
Estimate reserve information average realized prices \| $				$ 85.59	$ 72.51	$ 54.65
Proved reserves \| MBbls				31,532	23,239	34,082	49,487
Proved undeveloped reserves \| MBbls				13,660	6,189	13,457
Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Textual) [Abstract]
Proved reserves from drilling activities and evaluations of proved areas \| MBbls				4,915	4,663	3,479
Revision of previous estimates \| MBbls				6,522	(2,672)	(1,536)
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production
Estimate reserve information average realized prices \| $				$ 49.24	$ 39.14	$ 34.05
Proved reserves \| MBbls				142,515	122,722	51,588	23,849
Proved undeveloped reserves \| MBbls				78,043	69,651	25,382
Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Textual) [Abstract]
Proved reserves from drilling activities and evaluations of proved areas \| MBbls				26,591	48,792	21,492
Revision of previous estimates \| MBbls				18,627	26,832	8,434
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production
Estimate reserve information average realized prices \| $				$ 3.55	$ 3.70	$ 3.19
Proved reserves \| MMcf				4,009,676	3,566,526	2,614,717	2,213,546
Proved undeveloped reserves \| MMcf				2,102,467	1,803,760	1,169,012
Supplemental Information on Natural Gas and Oil Exploration Development and Production Activities (Textual) [Abstract]
Proved reserves from drilling activities and evaluations of proved areas \| MMcf				1,304,324	1,089,632	620,114
Revision of previous estimates \| MMcf				73,643	3,599	(37,497)

Label	Element	Value
Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas	rrc_StandardizedMeasureOfDiscountedFutureNetCashFlowRelatingToProvedOilAndGas	$ 4,514,897,000

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	$ 251,300
Fair Value, Measurements, Recurring [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Trading securities held in our deferred compensation plans	50,237	$ 47,794
Fair Value, Measurements, Recurring [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	211,621	170,140
Fair Value, Measurements, Recurring [Member] \| Collars discontinued operations [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		8,195
Fair Value, Measurements, Recurring [Member] \| Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	69,054
Fair Value, Measurements, Recurring [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		(352)
Fair Value, Measurements, Recurring [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	(29,348)	(60,297)
Fair Value, Measurements, Recurring [Member] \| 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	50,237	47,794
Fair Value, Measurements, Recurring [Member] \| Quoted Prices in Active Markets for Identical Assets [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	0	0
Fair Value, Measurements, Recurring [Member] \| Quoted Prices in Active Markets for Identical Assets [Member] \| Collars discontinued operations [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		0
Fair Value, Measurements, Recurring [Member] \| Quoted Prices in Active Markets for Identical Assets [Member] \| Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	0
Fair Value, Measurements, Recurring [Member] \| Quoted Prices in Active Markets for Identical Assets [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		0
Fair Value, Measurements, Recurring [Member] \| Quoted Prices in Active Markets for Identical Assets [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	0	0
Fair Value, Measurements, Recurring [Member] \| 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
Fair Value, Measurements, Recurring [Member] \| Significant Other Observable Inputs [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	211,621	170,140
Fair Value, Measurements, Recurring [Member] \| Significant Other Observable Inputs [Member] \| Collars discontinued operations [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		8,195
Fair Value, Measurements, Recurring [Member] \| Significant Other Observable Inputs [Member] \| Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	69,054
Fair Value, Measurements, Recurring [Member] \| Significant Other Observable Inputs [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		(352)
Fair Value, Measurements, Recurring [Member] \| Significant Other Observable Inputs [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	(29,348)	(60,297)
Fair Value, Measurements, Recurring [Member] \| 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
Fair Value, Measurements, Recurring [Member] \| Significant Unobservable Inputs [Member] \| Collars [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	0	0
Fair Value, Measurements, Recurring [Member] \| Significant Unobservable Inputs [Member] \| Collars discontinued operations [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		0
Fair Value, Measurements, Recurring [Member] \| Significant Unobservable Inputs [Member] \| Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	0
Fair Value, Measurements, Recurring [Member] \| Significant Unobservable Inputs [Member] \| Basis Swap [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net		0
Fair Value, Measurements, Recurring [Member] \| Significant Unobservable Inputs [Member] \| Call Option [Member]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value
Derivative assets liabilities at fair value net	$ 0	$ 0