Range Resources (RRC) 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 22, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	RRC
Entity Registrant Name	RANGE RESOURCES CORP
Entity Central Index Key	315,852
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		169,585,625
Entity Public Float			$ 8,138,124,000

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 471	$ 448
Accounts receivable, less allowance for doubtful accounts of $4,994 and $2,719		123,842	188,941
Derivative assets		281,544	363,049
Inventory and other		33,217	17,854
Total current assets		439,074	570,292
Derivative assets		7,218	40,314
Natural gas and oil properties, successful efforts method	[1]	8,996,336	10,567,971
Accumulated depletion and depreciation	[1]	(2,635,031)	(2,590,398)
Natural gas and oil properties, successful efforts method, net	[1]	6,361,305	7,977,573
Other property and equipment		110,013	127,808
Accumulated depreciation and amortization		(90,558)	(90,227)
Other Property and equipment, net		19,455	37,581
Other assets		72,979	78,844
Total assets		6,900,031	8,704,604
Current liabilities:
Accounts payable		117,346	396,942
Asset retirement obligations		15,071	15,067
Accrued liabilities		188,028	187,973
Accrued interest		30,139	39,695
Derivative liabilities		1,136	0
Total current liabilities		351,720	639,677
Bank debt		86,427	713,221
Senior notes		738,101	0
Senior subordinated notes		1,826,775	2,317,603
Deferred tax liabilities		777,947	1,113,081
Derivative liabilities		21	0
Deferred compensation liabilities		104,792	178,599
Asset retirement obligations and other liabilities		254,590	284,994
Total liabilities		4,140,373	5,247,175
Commitments and contingencies		0	0
Stockholders' Equity
Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding		0	0
Common stock, $0.01 par 475,000,000 shares authorized, 169,375,743 issued at December 31, 2015 and 168,711,131 issued at December 31, 2014		1,693	1,687
Common stock held in treasury, 59,283 shares at December 31, 2015 and 82,954 shares at December 31, 2014		(2,245)	(3,088)
Additional paid-in capital		2,442,623	2,400,475
Retained earnings		317,587	1,058,355
Total stockholders' equity		2,759,658	3,457,429
Total liabilities and stockholders' equity		$ 6,900,031	$ 8,704,604
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 4,994	$ 2,719
Preferred stock, par value	$ 1	$ 1
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	475,000,000	475,000,000
Common stock, shares issued	169,375,743	168,711,131
Common stock held in treasury, shares	59,283	82,954

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other income:
Natural gas, NGLs and oil sales	$ 254,043	$ 252,065	$ 258,053	$ 325,483	$ 416,388	$ 446,067	$ 477,517	$ 572,017	$ 1,089,644	$ 1,911,989	$ 1,715,676
Derivative fair value income (loss)	126,312	202,004	(34,791)	122,839	412,422	142,057	(24,109)	(146,850)	416,364	383,520	(61,825)
Brokered natural gas, marketing and other	30,372	25,864	21,339	14,485	39,644	28,324	30,052	32,528	92,060	130,548	116,577
Total revenues and other income	410,727	479,933	244,601	462,807	868,454	616,448	483,460	457,695	1,598,068	2,426,057	1,770,428
Costs and expenses:
Direct operating	29,388	35,058	34,780	37,137	37,961	37,792	34,935	39,795	136,363	150,483	128,091
Transportation, gathering and compression	112,481	99,634	95,198	89,426	89,542	84,777	76,809	74,161	396,739	325,289	256,242
Production and ad valorem taxes	7,354	7,336	9,242	9,928	11,923	10,110	10,844	11,678	33,860	44,555	45,240
Brokered natural gas and marketing	34,942	32,331	27,031	21,562	32,370	28,706	34,775	34,129	115,866	129,980	131,786
Exploration	4,260	4,235	5,025	7,886	23,638	11,443	13,621	14,846	21,406	63,548	64,409
Abandonment and impairment of unproved properties	11,432	12,366	12,330	11,491	14,308	13,444	9,332	9,995	47,619	47,079	51,918
General and administrative	43,544	46,178	55,964	48,329	52,363	54,963	56,888	49,212	194,015	213,426	291,171
Termination costs	8,780	(77)	417	5,950	8,371				15,070	8,371	0
Deferred compensation plan	(21,016)	(43,705)	(7,282)	(5,624)	(36,836)	(46,198)	10,519	(2,035)	(77,627)	(74,550)	55,296
Interest	40,849	42,904	43,479	39,207	38,900	39,188	45,488	45,401	166,439	168,977	176,557
Loss on early extinguishment of debt		22,495					24,596		22,495	24,596	12,280
Depletion, depreciation and amortization	127,977	153,993	151,895	147,290	146,539	142,450	133,361	128,682	581,155	551,032	492,397
Impairment of proved properties and other assets	87,941	502,233			3,033		24,991		590,174	28,024	7,753
Loss (gain) on the sale of assets	408,909	681	(2,909)	175	(3,760)	(167)	(282,064)	353	406,856	(285,638)	(92,291)
Total costs and expenses	896,841	915,662	425,170	412,757	418,352	376,508	194,095	406,217	2,650,430	1,395,172	1,620,849
(Loss) income before income taxes	(486,114)	(435,729)	(180,569)	50,050	450,102	239,940	289,365	51,478	(1,052,362)	1,030,885	149,579
Income tax (benefit) expense:
Current	29				(4)		(1)	6	29	1	(143)
Deferred	(164,316)	(134,781)	(61,975)	22,366	166,052	93,522	117,977	18,951	(338,706)	396,502	34,000
Total income tax expense	(164,287)	(134,781)	(61,975)	22,366	166,048	93,522	117,976	18,957	(338,677)	396,503	33,857
Net (loss) income	$ (321,827)	$ (300,948)	$ (118,594)	$ 27,684	$ 284,054	$ 146,418	$ 171,389	$ 32,521	$ (713,685)	$ 634,382	$ 115,722
Net (loss) income per common share:
Basic	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ 1.68	$ 0.87	$ 1.04	$ 0.20	$ (4.29)	$ 3.81	$ 0.71
Diluted	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ 1.68	$ 0.86	$ 1.04	$ 0.20	$ (4.29)	$ 3.79	$ 0.70
Weighted average common shares outstanding:
Basic									166,389	163,625	160,438
Diluted									166,389	164,403	161,407

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net (loss) income		$ (713,685)	$ 634,382	$ 115,722
Other comprehensive income:
Realized gain on hedge derivative contract settlements reclassified into natural gas, NGLs and oil sales from other comprehensive income, net of taxes	[1]	0	0	(14,840)
De-designated hedges reclassified into natural gas, NGLs and oil sales, net of taxes	[2]	0	(6,236)	(56,254)
De-designated hedges reclassified to derivative fair value, net of taxes	[3]	0	0	(2,376)
Change in unrealized deferred hedging losses, net of taxes	[4]	0	0	(4,203)
Total comprehensive (loss) income	[5]	$ (713,685)	$ 628,146	$ 38,049
[1]	Amounts are net of income tax benefit of $9,488 for the year ended December 31, 2013.
[2]	Amounts are net of income tax benefit of $3,986 for the year ended December 31, 2014 compared to $35,968 for the year ended December 31, 2013.
[3]	Amounts relate to transactions not probable of occurring and are presented net of income tax benefit of $1,517 for the year ended December 31, 2013.
[4]	Amounts are net of income tax benefit of $2,687 for the year ended December 31, 2013.
[5]	As of March 31, 2013, we elected to discontinue hedge accounting prospectively, and as of December 31, 2014, all remaining accumulated other comprehensive income had been transferred to earnings.

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Realized loss (gain) on hedge derivative contract settlements reclassified into natural gas, NGLs and oil sales from other comprehensive income, tax portion		$ 9,488
De-designated hedges reclassified into natural gas, NGLs and oil sales, tax portion	$ 3,986	35,968
De-designated hedges reclassified to derivative fair value income, tax portion		1,517
Change in unrealized deferred hedging (losses) gains, tax effect		$ 2,687

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net (loss) income	$ (713,685)	$ 634,382	$ 115,722
Adjustments to reconcile net (loss) income to net cash provided from operating activities:
Loss (gain) from equity method investments, net of distributions		3,095	(2,973)
Deferred income tax (benefit) expense	(338,706)	396,502	34,000
Depletion, depreciation and amortization and impairment	1,171,329	579,056	500,150
Exploration dry hole and impairment costs	88	16,145	5,699
Abandonment and impairment of unproved properties	47,619	47,079	51,918
Derivative fair value (income) loss	(416,364)	(383,520)	61,825
Cash settlements on derivative financial instruments that do not qualify for hedge accounting	532,122	(42,634)	(31,256)
Allowance for bad debt	2,300	250	250
Amortization of deferred financing costs, loss on extinguishment of debt and other	29,383	24,694	23,866
Deferred and stock-based compensation	(20,411)	(4,295)	119,398
Loss (gain) on the sale of assets	406,856	(285,638)	(92,291)
Changes in working capital:
Accounts receivable	64,704	(5,329)	(21,212)
Inventory and other	(14,868)	(4,521)	3,785
Accounts payable	(26,197)	(1,023)	(13,555)
Accrued liabilities and other	(40,470)	(20,108)	(11,788)
Net cash provided from operating activities	683,700	954,135	743,538
Investing activities:
Additions to natural gas and oil properties	(1,030,644)	(1,200,419)	(1,159,252)
Additions to field service assets	(4,441)	(11,863)	(5,925)
Acreage purchases	(74,880)	(211,971)	(132,145)
Other	(75)	1,103	3,799
Proceeds from disposal of assets	890,901	180,508	315,522
Purchases of marketable securities held by the deferred compensation plan	(28,876)	(30,898)	(36,136)
Proceeds from the sales of marketable securities held by the deferred compensation plan	29,243	28,084	30,701
Net cash used in investing activities	(218,772)	(1,245,456)	(983,436)
Financing activities:
Borrowings on credit facilities	2,271,000	2,107,000	1,684,000
Repayments on credit facilities	(2,899,000)	(1,884,000)	(1,923,000)
Issuance of senior or senior subordinated notes	750,000	0	750,000
Repayment of senior subordinated notes	(516,875)	(312,000)	(259,063)
Dividends paid	(27,083)	(26,610)	(26,129)
Debt issuance costs	(14,156)	(8,866)	(12,448)
Issuance of common stock		396,562	343
Change in cash overdrafts	(37,089)	3,371	5,610
Proceeds from the sales of common stock held by the deferred compensation plan	8,298	15,964	20,681
Net cash (used in) provided from financing activities	(464,905)	291,421	239,994
Increase in cash and cash equivalents	23	100	96
Cash and cash equivalents at beginning of year	448	348	252
Cash and cash equivalents at end of year	$ 471	$ 448	$ 348

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Treasury common stock	Additional paid-in capital	Retained earnings	Accumulated other comprehensive income (loss)
Beginning balance at Dec. 31, 2012	$ 2,357,392	$ 1,626	$ (4,760)	$ 1,915,627	$ 360,990	$ 83,909
Beginning balance Shares at Dec. 31, 2012		162,642,000
Issuance of common stock	9,289	$ 8	0	9,281	0	0
Issuance of common stock, shares		799,000
Stock-based compensation expense	35,851	$ 0	0	35,851	0	0
Common dividends declared ($0.16 per share)	(26,129)	0	0	0	(26,129)	0
Treasury stock issuance	0	0	1,123	(1,123)	0	0
Other comprehensive income (loss)	(77,673)	0	0	0	0	(77,673)
Net (loss) income	115,722	0	0	0	115,722	0
Ending balance at Dec. 31, 2013	2,414,452	$ 1,634	(3,637)	1,959,636	450,583	6,236
Ending balance Shares at Dec. 31, 2013		163,441,000
Issuance of common stock	398,607	$ 53	0	398,554	0	0
Issuance of common stock, shares		5,270,000
Stock-based compensation expense	42,834	$ 0	0	42,834	0	0
Common dividends declared ($0.16 per share)	(26,610)	0	0	0	(26,610)	0
Treasury stock issuance	0	0	549	(549)	0	0
Other comprehensive income (loss)	(6,236)	0	0	0	0	(6,236)
Net (loss) income	634,382	0	0	0	634,382	0
Ending balance at Dec. 31, 2014	$ 3,457,429	$ 1,687	(3,088)	2,400,475	1,058,355	0
Ending balance Shares at Dec. 31, 2014	168,711,131	168,711,131
Issuance of common stock	$ 10,073	$ 6	0	10,067	0	0
Issuance of common stock, shares		665,000
Stock-based compensation expense	36,496	$ 0	0	36,496	0	0
Tax benefit related to stock-based compensation	(3,572)	0	0	(3,572)	0	0
Common dividends declared ($0.16 per share)	(27,083)	0	0	0	(27,083)	0
Treasury stock issuance	0	0	843	(843)	0	0
Net (loss) income	(713,685)	0	0	0	(713,685)	0
Ending balance at Dec. 31, 2015	$ 2,759,658	$ 1,693	$ (2,245)	$ 2,442,623	$ 317,587	$ 0
Ending balance Shares at Dec. 31, 2015	169,375,743	169,375,743

CONSOLIDATED STATEMENTS OF SHA9

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Of Stockholders Equity [Abstract]
Common 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

Summary of Organization and Nat

Summary of Organization and Nature of Business	12 Months Ended
	Dec. 31, 2015
Industry Specific Policies [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, NGLs and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian region 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 Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 brokered natural gas, marketing and other revenues in the accompanying consolidated statements of operations. As of June 2014, we no longer have equity method investments. All material intercompany balances and transactions have been eliminated. Use of Estimates The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. 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 to the current year presentation. This includes reclassification of deferred income tax balances included in the consolidated balance sheets from current to long-term and the reclassification of debt issuance costs included in the consolidated balance sheets from other assets to offset our debt balances. These reclassifications were made as a result of our adoption of new accounting pronouncements and did not impact our net loss, stockholders’ equity or cash flows. 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 in the United States. We consider our gathering, processing and marketing functions as integral 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 a geographical or 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. Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is reasonably assured. 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. We are reporting our gathering and transportation costs in accordance with Accounting Standards Code 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 receive from the purchaser. For the sale of our NGLs, we receive a price from the purchaser (which is net of processing costs) that is recorded in revenue at the net price we receive. Under the other type of agreement, we sell natural gas or oil at a specific delivery point, pay transportation, gathering and compression expenses to a third party and receive proceeds from the purchaser with no 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. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby Range or the counterparty takes titles to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. In 2013, we also included purchased (and sold) natural gas which was used to blend our rich residue gas from the Southwest Marcellus Shale. In 2014, we also included additional broker revenues and broker expenses from the release of transportation capacity where we had taken firm transportation ahead of our production volumes. Our net brokered margin was a loss of $2.7 million in 2015 compared to a gain of $9.4 million in 2014 and a loss of $5.7 million in 2013. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $5.0 million at December 31, 2015 compared to $2.7 million at December 31, 2014. We recorded bad debt expense of $2.3 million in the year ended December 31, 2015 compared to $250,000 in both the years ended December 31, 2014 and 2013. Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. Imbalances are not significant in the periods presented. 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. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts are classified as financing activities on the consolidated statements of cash flows. 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 include equity securities and money market instruments. Inventory Inventories were comprised of $20.8 million of materials and supplies at December 31, 2015 compared to $11.8 million at December 31, 2014. Inventories consist primarily of tubular goods and equipment 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 material and supplies inventory is primarily acquired for use in future drilling operations or repair operations. At December 31, 2015, we also had commodity inventory of $4.8 million, compared to $2.0 million at December 31, 2014, which is carried at lower of average cost or market, on a first-in, first-out basis. Commodity inventory at December 31, 2015 consists of natural gas and NGLs held in storage or as line fill in pipelines. Natural Gas and Oil Properties Property Acquisition Costs . We use 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. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended exploratory well costs, see Note 6. Depreciation, Depletion and Amortization . Depreciation, depletion and amortization of proved producing properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, 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 at other times during the year when circumstances indicate there has been a significant change in reserves or costs. Impairments . Our proved natural gas and oil properties are reviewed for impairment annually and 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 impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. 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, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. 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 undiscounted 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 11. 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 $949.2 million as of December 31, 2015 compared to $943.2 million in 2014. We have recorded abandonment and impairment expense related to unproved properties of $47.6 million in the year ended December 31, 2015 compared to $47.1 million in 2014 and $51.9 million in 2013. Dispositions . Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base 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. For additional information regarding our dispositions, see Note 3. Acquisitions . Acquisitions of proved properties are accounted for as business combinations and, accordingly, the results of operations are included in the accompanying consolidated 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. Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and 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 three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $11.9 million in the year ended December 31, 2015 compared to $12.9 million in the year ended December 31, 2014 and $13.2 million in the year ended December 31, 2013. Other Assets Other assets at December 31, 2015 include $62.4 million of marketable securities held in our deferred compensation plans and $10.6 million of other investments including surface acreage. Other assets at December 31, 2014 include $68.5 million of marketable securities held in our deferred compensation plans and $10.3 million of other investments including surface acreage. Stock-based Compensation Arrangements The fair value of performance share unit awards (“PSUs”) is estimated on the date of grant using a Monte Carlo simulation method. A Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant. The fair value of stock-settled stock appreciation rights (“SARs”) is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The models employ 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 awards. 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. The majority of our Liability Awards are deposited in our deferred compensation plan 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 consolidated statements 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. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm, when they are governed by master netting agreements. 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. Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. For more information, see Note 10. The effective portions of the discontinued deferred hedges as of March 1, 2013 were included in accumulated other comprehensive income (“AOCI”) and were transferred to earnings during the same periods in which the forecasted transactions were recognized in earnings. During 2014, the remaining AOCI hedging gains were transferred to earnings. Since discontinuing hedge accounting, all realized and unrealized gains and losses on 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 in the accompanying consolidated statements of operations. At times, we have also entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. We have not acquired any hedges through a business combination and have not modified any existing derivative contracts. Concentrations of Credit Risk As of December 31, 2015, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and are generally unsecured. To manage risks of collecting accounts receivable, we monitor our counterparties financial strength and/or credit ratings and where we deem necessary, obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $5.0 million at December 31, 2015 compared to $2.7 million at December 31, 2014. For the year ended December 31, 2015, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. For both of the years ended December 31, 2014 and December 31, 2013, we had four 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. We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have margin requirements or collateral provisions that would require us to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2015, our derivative counterparties included seventeen financial institutions and commodity traders of which all but four are secured lenders in our bank credit facility. At December 31, 2015, our net derivative asset includes a receivable from the counterparties not included in our bank credit facility totaling $11.5 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance. 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 of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 8 for additional information. Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed. 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 may include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. We do not recognize a deferred tax asset for excess tax benefits on equity compensation that have not been realized due to our net operating loss tax position for federal or state tax purposes. All deferred taxes are classified as long-term on the balance sheet. Accumulated Other Comprehensive The following details the components of AOCI and related tax effects for the two years ended December 31, 2014 (in thousands). Amounts included in AOCI exclusively relate to our derivative activity. See Note 10 for additional information on the discontinuance of hedge accounting. Gross Tax Effect Net of Tax Accumulated other comprehensive income at December 31, 2012 $ 137,555 $ (53,646 ) $ 83,909 Contract settlements reclassified to income (120,443 ) 46,973 (73,470 ) Change in unrealized deferred hedging gains (6,890 ) 2,687 (4,203 ) Accumulated other comprehensive income at December 31, 2013 10,222 (3,986 ) 6,236 Contract settlements reclassified to income (10,222 ) 3,986 (6,236 ) Accumulated other comprehensive income at December 31, 2014 $ ¾ $ ¾ $ ¾ New Accounting Pronouncements Recently Adopted In April 2014, an accounting standards update was issued that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption was permitted but only for disposals (or classifications that are held for sale) that had not been reported in financial statements previously issued or available for use. We adopted this new standard in first quarter 2014 and, as a result, the Conger Exchange defined and described in more detail below, was not reported as a discontinued operation. In April 2015, an accounting standards update was issued that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for the reporting period beginning on January 1, 2016 with early adoption permitted. As of December 31, 2015, we have adopted this standard retrospectively and have accounted for the debt issuance costs as a reduction of the associated debt liability. Previously, these costs were reported in other long-term assets. We reclassified $9.8 million from other long-term assets to bank debt and $32.4 million from other long-term assets to subordinated notes as of December 31, 2014. This adoption only affected our consolidated balance sheet and did not have an impact on our consolidated results of operations or cash flows. In November 2015, an accounting standards update was issued which requires entities to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This standard is effective for the reporting period beginning in January 1, 2017 with early adoption permitted. As of December 31, 2015, we have adopted this standard retrospectively and have reclassified our December 31, 2014 current deferred tax assets and liabilities into non-current deferred tax assets and liabilities. We reclassified $115.6 million current deferred tax liabilities into non-current deferred tax liabilities as of December 31, 2014. This adoption only affected our consolidated balance sheets and did not have an impact on our consolidated results of operations or cash flows. Accounting Pronouncements Not Yet Adopted In May 2014, an accounting standards update was issued that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in first quarter 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter 2017. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows. In August 2014, an accounting standards update was issued that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. This standard is effective for us in first quarter 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Dispositions	(3) Acquisitions and Dispositions We recognized a pretax net loss on the sale of assets of $406.9 million in the year ended December 31, 2015 compared to a gain of $285.6 million in 2014 and a gain of $92.3 million in 2013. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2015, 2014 and 2013. 2015 Dispositions Virginia and West Virginia . In December 2015, we sold the majority of our producing properties and gathering assets in Virginia and West Virginia for cash proceeds of $876.0 million, before closing adjustments. We recorded a pretax loss of $407.7 million related to this sale. We recognized $52.3 million of field net operating income (defined as natural gas, oil and NGLs sales plus net brokered margin less direct operating expenses, production and ad valorem taxes, transportation expense, exploration expense and divisional office general and administrative expense) for these assets for the period from January 1, 2015 to December 30, 2015 compared to $98.3 million in the year ended December 31, 2014 and $46.1 million in the year ended December 31, 2013. West Texas. In February 2015, we sold certain of our West Texas properties for cash proceeds of $10.5 million and we recognized a pretax loss of $101,000. Other. During 2015, we also sold miscellaneous inventory, surface acreage and unproved property for proceeds of $4.4 million and recorded a gain of $943,000. 2014 Dispositions Conger Exchange Transaction. In April 2014, we entered into an exchange agreement with EQT Corporation and certain of its affiliates (collectively, “EQT”) in which we sold our Conger assets in Glasscock and Sterling Counties, Texas in exchange for producing properties and gas gathering assets in Virginia and $145.0 million in cash, before closing adjustments (“the Conger Exchange”). We closed the exchange transaction in June 2014 and recognized a pretax gain of $272.7 million, after selling expenses of $5.0 million, which is recognized as a gain on sale of assets in our consolidated statements of operations for the year ended December 31, 2014. For the period from January 1, 2014 through June 16, 2014, we recognized $21.9 million of field net operating income (defined as natural gas, oil and NGLs sales plus net brokered margin less direct operating expenses, production and ad valorem taxes and transportation expenses) for our Conger assets compared to $48.7 million for the year ended December 31, 2013. In connection with the Conger Exchange, we acquired the remaining 50% interest held by EQT in Nora Gathering, LLC (“NGLLC”), a natural gas gathering operation, which we had previously accounted for using the equity method of accounting. As of June 2014, we consolidated NGLLC into our consolidated financial statements. Our previous 50% membership interest in NGLLC was remeasured to fair value of $134.8 million on the acquisition date, resulting in a gain of $10.0 million which is recognized in gain on sale of assets in our consolidated statements of operations for the year ended December 31, 2014. For the period from June 16, 2014 through December 31, 2014, we recognized $33.8 million of natural gas, oil and NGLs sales from the property interests acquired in the Conger Exchange and we recognized $25.7 million of field net operating income from the property interests acquired in the Conger Exchange. Conger Exchange Fair Value. Accounting standards define fair value as 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 (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views. The fair value of the Conger Exchange described above was based on an income approach which was supplemented by a market approach. For the natural gas and oil properties, the income approach uses significant inputs not observable in the market, which are Level 3 inputs. The significant inputs assumed include future production, costs and capital, commodity prices, risk-adjusted discount rates, natural gas and oil pricing differentials, and projected reserve recovery factors. The market approach uses inputs such as recent market transactions in a similar geographic region and with similar production. The income approach for the natural gas gathering operations was based on a discounted future net cash flow model, which uses Level 3 inputs and was supplemented by a market approach. Other. During 2014, we also sold miscellaneous proved and unproved oil and gas properties, inventory and other property and equipment for proceeds of $35.5 million and recognized a pretax gain of $3.0 million. 2013 Dispositions Southeast New Mexico and West Texas. In April 2013, we completed the sale of our Delaware and Permian Basin properties in Southeast New Mexico and West Texas for a price of $275.0 million and we recognized a pretax gain of $83.3 million, before selling expenses of $4.2 million. Other. During 2013, we also sold miscellaneous proved and unproved oil and gas properties, inventory, and other property and equipment for proceeds of $40.5 million and recorded a pretax gain of $13.2 million.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	(4) Income Taxes Our income tax benefit was $338.7 million for the year ended December 31, 2015 compared to income tax expense of $396.5 million in 2014 and income tax expense of $33.9 million in 2013. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2015 2014 2013 Federal statutory tax rate 35.0 % 35.0 % 35.0 % State 4.3 3.1 (2.3 ) State apportionment rate change (0.2 ) (0.2 ) (14.9 ) Non-deductible executive compensation (0.1 ) 0.2 0.7 Valuation allowances (6.8 ) 0.2 3.5 Other ¾ 0.2 0.6 Consolidated effective tax rate 32.2 % 38.5 % 22.6 % Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands): 2015 2014 2013 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ ¾ $ (328,257 ) $ (328,257 ) $ ¾ $ 361,152 $ 361,152 $ ¾ $ 58,527 $ 58,527 U.S. state and local 29 (10,449 ) (10,420 ) 1 35,350 35,351 (143 ) (24,527 ) (24,670 ) Total $ 29 $ (338,706 ) $ (338,677 ) $ 1 $ 396,502 $ 396,503 $ (143 ) $ 34,000 $ 33,857 Significant components of deferred tax assets and liabilities are as follows: December 31, 2015 2014 (in thousands) Deferred tax assets: Net operating loss carryforward $ 173,503 $ 176,812 Deferred compensation 45,413 73,942 Equity compensation 25,940 25,833 AMT credits and other credits 4,437 4,447 Asset retirement obligation 101,142 109,808 Cumulative mark-to-market loss ¾ 649 Other 10,163 10,908 Valuation allowances: Federal (42,500 ) ¾ State, net of federal benefit (41,516 ) (8,800 ) Deferred compensation plans and other (3,607 ) (7,799 ) Total deferred tax assets 272,975 385,800 Deferred tax liabilities: Depreciation, depletion and investments (940,482 ) (1,342,038 ) Cumulative mark-to-market gain (109,845 ) (154,183 ) Other (595 ) (2,660 ) Total deferred tax liabilities (1,050,922 ) (1,498,881 ) Net deferred tax liability $ (777,947 ) $ (1,113,081 ) At December 31, 2015, deferred tax liabilities exceeded deferred tax assets by $777.9 million. As of December 31, 2015, we have a valuation allowance of $3.1 million 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). During 2015, we adjusted our state net operating loss and credit carryforwards by a total of $32.7 million. This amount includes $15.6 million in net operating loss carryforwards for Louisiana, Mississippi, Oklahoma and West Virginia and establishes a full valuation for these states where we do not expect to generate any taxable income in the future due to completed or anticipated sales. We established a valuation allowance in 2015 related to our Pennsylvania net operating loss carryforwards of $16.0 million due to the low commodity price environment and the limitation Pennsylvania places on future utilization of net operating loss carryforwards. We also recorded a $1.0 million valuation allowance related to our Texas Margin Tax credit carryforward. In addition, during 2015 we have recorded a valuation allowance of $42.5 million related to our federal net operating loss carryforwards which we expect will expire unused based exclusively on our estimated turn of temporary difference in the next four years. At December 31, 2015, we had regular net operating loss (“NOL”) carryforwards of $620.6 million and alternative minimum tax (“AMT”) NOL carryforwards of $539.3 million that expire between 2018 and 2035. Our federal deferred tax asset related to regular NOL carryforwards at December 31, 2015 was $123.5 million, which is net of the Accounting Standards Codification 718, “Stock Compensation” reduction for unrealized benefits, related to NOL’s created by excess tax deductions that have not generated current tax benefits. At December 31, 2015, 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 Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years 2012 and after and we are subject to various state tax examinations for years 2011 and after. 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, 2015. Throughout 2015, our unrecognized tax benefits were not material.

Net (Loss) Income Per Common Sh

Net (Loss) Income Per Common Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Net (Loss) Income Per Common Share	(5) Net (Loss) Income per Common Share Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (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 stockholders (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 net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts): Year Ended December 31, 2015 2014 2013 Net (loss) income, as reported $ (713,685 ) $ 634,382 $ 115,722 Participating basic earnings (a) (450 ) (10,725 ) (1,975 ) Basic net (loss) income attributed to common stockholders (714,135 ) 623,657 113,747 Reallocation of participating earnings (a) ¾ 48 9 Diluted net (loss) income attributed to common stockholders $ (714,135 ) $ 623,705 $ 113,756 Net (loss) income per common share: Basic $ (4.29 ) $ 3.81 $ 0.71 Diluted $ (4.29 ) $ 3.79 $ 0.70 (a) Restricted stock Liability 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, 2015 2014 2013 Denominator: Weighted average common shares outstanding – basic 166,389 163,625 160,438 Effect of dilutive securities: Director and employee SARs and restricted stock Equity Awards ¾ 778 969 Weighted average common shares outstanding – diluted 166,389 164,403 161,407 Weighted average common shares – basic excludes 2.8 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for all of the periods ending December 31, 2015, December 31, 2014 and December 31, 2013. Due to our net loss for the year ended December 31, 2015, we excluded all outstanding stock appreciation rights and restricted stock from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. SARs of 1,900 for the year ended December 31, 2014 compared to 226,000 in 2013 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 Cost

Suspended Exploratory Well Costs	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Suspended Exploratory Well Costs	(6) Suspended Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015, 2014 and 2013 (in thousands, except for number of projects): 2015 2014 2013 Balance at beginning of period $ 2,996 $ 6,964 $ 57,360 Additions to capitalized exploratory well costs pending the determination of proved reserves 1,165 18,747 39,832 Reclassifications to wells, facilities and equipment based on determination of proved reserves ¾ (15,735 ) (84,840 ) Capitalized exploratory well costs charged to expense ¾ (6,980 ) (5,388 ) Balance at end of period 4,161 2,996 6,964 Less exploratory well costs that have been capitalized for a period of one year or less (1,165) (2,996 ) ¾ Capitalized exploratory well costs that have been capitalized for a period greater than one year $ 2,996 $ ¾ $ 6,964 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 1 ¾ 1 As of December 31, 2015, the $3.0 million of capitalized exploratory well costs that have been capitalized for more than one year is comprised of one well in our Marcellus Shale area which is currently in the completion phase. The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of December 31, 2015 (in thousands): Total 2015 2014 Capitalized exploratory well costs that have been suspended for more than one year $ 2,996 $ ¾ $ 2,996

Indebtedness

Indebtedness	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Indebtedness	(7) Indebtedness We had the following debt outstanding as of the dates shown below which are net of debt issuance costs (bank debt interest rate at December 31, 2015 is shown parenthetically) (in thousands). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2015, 2014, and 2013. December 31, 2015 2014 Bank debt (1.8%), net of unamortized debt issuance costs of $8,573 and $9,779 $ 86,427 $ 713,221 Senior notes: 4.875% senior notes due 2025, net of unamortized debt issuance costs of $11,899 738,101 ¾ Senior subordinated notes: 6.75% senior subordinated notes due 2020, net of unamortized debt issuance costs of $6,157 ¾ 493,843 5.75% senior subordinated notes due 2021, net of unamortized debt issuance costs of $5,905 and $6,803 494,095 493,197 5.00% senior subordinated notes due 2022, net of unamortized debt issuance costs of $7,777 and $8,820 592,223 591,180 5.00% senior subordinated notes due 2023, net of unamortized debt issuance costs of $9,543 and $10,617 740,457 739,383 Total debt $ 2,651,303 $ 3,030,824 Bank Debt In October 2014, 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 has a maximum facility amount of $4.0 billion. As of December 31, 2015, the facility had a borrowing base of $3.0 billion and bank commitments of $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually each May and for event-driven unscheduled redeterminations. As part of our annual redetermination completed on March 31, 2015, our borrowing base was reaffirmed at $3.0 billion and our bank commitment was also reaffirmed at $2.0 billion. Our current bank group is comprised of twenty-nine financial institutions, with no one bank holding more than 5.8% of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. The commitment matures on October 16, 2019. As of December 31, 2015, the outstanding balance under the bank credit facility was $95.0 million with $137.9 million of undrawn letters of credit leaving $1.8 billion of borrowing capacity available under the commitment amount. See additional discussion below under “ Debt Covenants and Maturity At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral security requirements, including the borrowing base requirement and restrictive covenants will cease to apply, certain other restrictive covenants will become less restrictive and an additional financial covenant (as defined in the bank credit facility) will be temporarily imposed. During the investment grade period, borrowings under the bank credit facility can either be at the ABR plus a spread ranging from 0.125% to 0.75% or LIBOR Rate plus a spread ranging from 1.125% to 1.75% depending on our debt rating. The commitment fee paid on the undrawn balance ranges from 0.15% to 0.30%. We currently do not have an investment grade rating. Senior Notes In May 2015, we issued $750.0 million aggregate principal amount of 4.875% senior notes due 2025 (the “4.875% Notes”) for net proceeds of $737.4 million after underwriting discounts and commissions of $12.6 million. The notes were issued at par. The 4.875% Notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S of the Securities Act of 1933, as amended (the “Securities Act”). Interest due on the 4.875% Notes is payable semi-annually in May and November and is unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. On or after February 15, 2025, we may redeem the notes, in whole or in part and from time to time, at 100% of the principal amount, plus accrued and unpaid interest. Upon the occurrence of certain changes in control, we must offer to repurchase the 4.875% Notes. The 4.875% Notes are unsecured and are subordinated to all of our existing and future secured debt, rank equally with all of our existing and future senior unsecured debt, and rank senior to all of our existing and future subordinated debt. On the closing of the 4.875% Notes, we used the net proceeds to repay borrowings under our bank credit facility pending our intended redemption of all of our 6.75% senior subordinated notes due 2020, which was completed in August 2015 using borrowings under our bank credit facility. Senior Subordinated Notes If we experience a change of control, noteholders 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 July 2015, we announced a call for the redemption of $500.0 million of our outstanding 6.75% senior subordinated notes due 2020 at a price of 103.375% of par plus accrued and unpaid interest, which were redeemed on August 3, 2015. In third quarter 2015, we recognized a loss on early extinguishment of debt of $22.5 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt. In 2014, we announced a call for the redemption of $300.0 million of our outstanding 8.0% senior subordinated notes due 2019 at 104.0% of par plus accrued and unpaid interest which were redeemed on June 26, 2014. In second quarter 2014, we recognized a $24.6 million loss on extinguishment of debt, including transaction call premium costs as well as expensing of the remaining deferred financing costs on the repurchased debt. In 2013, we announced a call for the redemption of $250.0 million of our outstanding 7.25% senior subordinated notes due 2018 at 103.625% of par which were redeemed on May 2, 2013. In second quarter 2013, we recognized a $12.3 million loss on extinguishment of debt, including transaction call premium costs as well as expensing of the remaining deferred financing costs on the repurchased debt. Guarantees Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly owned subsidiaries, which are directly or indirectly owned by Range, of our senior notes, our senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee: · in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or · if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture. 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 certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2015. 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, 2015, we were in compliance with these covenants. Our senior subordinated notes also include a limitation on the amount of credit facility debt we can incur. Certain thresholds, as set forth in the indenture debt incurrence test, may limit our ability to incur debt under our bank credit facility in excess of a $1.5 billion floor amount based on the levels of commodity prices for natural gas, NGLs and crude oil used in the annual calculation of discounted future net cash flows relating to proved oil and gas reserves. Based on the year-end 2015 discounted future net cash flows, our bank credit facility usage is limited to $1.5 billion until higher prices or proved reserve additions increase discounted future net cash flows. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2015 (in thousands): Year Ended 2016 $ — 2017 — 2018 — 2019 95,000 2020 — Thereafter 2,600,000 $ 2,695,000

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(8) Asset Retirement Obligations Our asset retirement obligations primarily represent the present value of the estimated 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 as of December 31, 2015 and 2014 are as follows (in thousands): 2015 2014 Beginning of period $ 287,463 $ 230,077 Liabilities incurred 4,595 8,602 Acquisitions 1,584 11,927 Liability released ¾ (8,309 ) Liabilities settled (18,828 ) (4,442 ) Disposition of wells (45,845 ) (13,951 ) Accretion expense 19,163 15,226 Change in estimate 16,005 48,333 End of period 264,137 287,463 Less current portion (15,071 ) (15,067 ) Long-term asset retirement obligations $ 249,066 $ 272,396 Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Capital Stock	(9) Capital Stock We have authorized capital stock of 485.0 million shares, which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2013: Year Ended December 31, 2015 2014 2013 Beginning balance 168,628,177 163,342,894 162,514,098 Equity offering − 4,560,000 − Stock options/SARs exercised 77,002 195,242 278,916 Restricted stock grants 335,103 270,062 401,122 Restricted stock units vested 252,507 244,413 119,480 Treasury shares 23,671 15,566 29,278 Ending balance 169,316,460 168,628,177 163,342,894 Common Stock Dividends The board of directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2015, 2014 and 2013. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings and cash flow from operations, level of capital expenditures, our future business prospects and other matters our board of directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations. Dividends are limited to our legally available funds.

Derivative Activities

Derivative Activities	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Activities	(10) Derivative Activities We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize commodity swap or collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. 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 pretax gain of $283.3 million at December 31, 2015. These contracts expire monthly through December 2017. The following table sets forth the derivative volumes by year as of December 31, 2015: Period Contract Type Volume Hedged Weighted Average Hedge Price Natural Gas 2016 Swaps 745,874 Mmbtu/day $3.24 2017 Swaps 20,000 Mmbtu/day $3.49 Crude Oil 2016 Swaps 4,247 bbls/day $65.27 2017 Swaps 500 bbls/day $55.00 NGLs (C3 - Propane) 2016 Swaps 5,500 bbls/day $0.60/gallon NGLs (NC4 – Normal Butane) 2016 Swaps 2,500 bbls/day $0.72/gallon NGLs (C5 - Natural Gasoline) 2016 Swaps 2,749 bbls/day $1.20/gallon Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Through February 28, 2013, changes in the fair value of our derivatives that qualified for hedge accounting were recorded as a component of AOCI in the stockholders’ equity section of the our consolidated balance sheets and were later transferred to natural gas, NGLs and oil sales when the underlying physical transaction occurred and the hedging contract was settled. Due to the discontinuance of hedge accounting in early 2013, all remaining AOCI hedging gains were transferred to earnings in 2014. See additional discussion below regarding the discontinuance of hedge accounting. 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 or loss. Basis Swap Contracts At December 31, 2015, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through March 2017 and include a total volume of 53,365,000 Mmbtu. The fair value of these contracts was a gain of $5.5 million on December 31, 2015. At December 31, 2015, we also had propane basis swap contracts which lock in the differential between Mont Belvieu and international propane indexes. The contracts settle monthly through December 2016 and include a total volume of 4,679 bbls/day. The fair value of these contracts was a loss of $1.1 million on December 31, 2015. Discontinuance of Hedge Accounting Effective March 1, 2013, we elected to de-designate all commodity contracts that were previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. AOCI included gains of $103.6 million ($63.2 million after tax) as of February 28, 2013. As a result of discontinuing hedge accounting, the mark-to-market values included in AOCI as of the de-designation date were frozen and were reclassified into earnings in natural gas, NGLs and oil sales in future periods as the underlying hedged transactions occurred. As of December 31, 2014, all frozen values have been reclassified to earnings. For those derivative instruments that qualified for hedge accounting, settled transaction gains and losses were determined monthly and were included as increases or decreases to natural gas, NGLs and oil sales in the period the hedged production was sold. Through February 28, 2013, we had elected to designate our commodity instruments that qualified for hedge accounting as cash flow hedges. Natural gas, NGLs and oil sales include $10.2 million of gains in 2014 compared to gains of $116.5 million in 2013 related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value income or loss in the accompanying consolidated 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. All of our derivative instruments continue to be recorded at fair value with all changes in fair value recognized immediately in earnings rather than in AOCI. These mark-to-market adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract. Derivative assets and liabilities The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2015 and 2014 is summarized below (in thousands). As of December 31, 2015, we are conducting derivative activities with seventeen counterparties, of which all but four are secured lenders in our bank credit facility. We believe all of these counterparties 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, 2015 Gross Amounts of Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 219,357 $ (10,245 ) $ 209,112 –natural gas basis swaps 8,251 (2,765 ) 5,486 Crude oil –swaps 38,699 ¾ 38,699 NGLs –C3 swaps 15,884 ¾ 15,884 –C3 basis 2,497 (2,497 ) ¾ –C4 swaps 6,968 ¾ 6,968 –C5 swaps 12,694 (81 ) 12,613 $ 304,350 $ (15,588 ) $ 288,762 December 31, 2015 Gross Amounts of Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ (10,245 ) $ 10,245 $ ¾ –natural gas basis swaps (2,786 ) 2,765 (21 ) NGLs –C3 basis (3,633 ) 2,497 (1,136 ) –C5 swaps (81 ) 81 ¾ $ (16,745 ) $ 15,588 $ (1,157 ) December 31, 2014 Gross Amounts of Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 198,740 $ ¾ $ 198,740 –collars 57,460 ¾ 57,460 –basis swaps 2,442 (755 ) 1,687 Crude oil –swaps 128,578 ¾ 128,578 NGLs –C3 swaps 14,727 ¾ 14,727 –C5 swaps 2,171 ¾ 2,171 $ 404,118 $ (755 ) $ 403,363 December 31, 2014 Gross Amounts of Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –basis swaps $ (755 ) $ 755 $ − $ (755 ) $ 755 $ − The effects of our non-hedge derivatives (or those derivatives that do not qualify or are not designated for hedge accounting) on our consolidated statements of operations for the last three years are summarized below (in thousands). Derivative fair value for the year ended December 31, 2014 includes no ineffective gains or losses compared to ineffective loss of $2.9 million in the year ended December 31, 2013. Year Ended December 31, Derivative Fair Value Income (Loss) 2015 2014 2013 Swaps $ 398,020 $ 367,484 $ (50,526 ) Re-purchased swaps 851 ¾ 1,323 Collars 16,539 42,836 (16,062 ) Basis swaps 954 (26,800 ) 3,440 Total $ 416,364 $ 383,520 $ (61,825 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	(11) Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do 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, 2015 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 62,376 $ ¾ $ ¾ $ 62,376 Derivatives –swaps ¾ 283,276 ¾ 283,276 –basis swaps ¾ 4,329 ¾ 4,329 Fair Value Measurements at December 31, 2014 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 68,454 $ — $ — $ 68,454 Derivatives –swaps — 344,216 — 344,216 –collars — 57,460 — 57,460 –basis swaps — 1,687 — 1,687 Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2015 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 consolidated statements of operations. For the year ended December 31, 2015, interest and dividends were $908,000 and mark-to-market was a loss of $5.9 million. For the year ended December 31, 2014, interest and dividends were $911,000 and mark-to-market was a loss of $2.4 million. For the year ended December 31, 2013, interest and dividends were $1.2 million and mark-to-market was a gain of $3.9 million. Fair Values-Non recurring Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying values of certain of our natural gas and oil properties may be impaired and undiscounted 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 some cases, we also considered the potential sale of certain of these properties. We recorded non-cash charges during the year ended 2015 related to natural gas and oil properties in Northern Oklahoma of $306.6 million, $195.6 million related to our shallow legacy oil and natural gas assets in Northwest Pennsylvania, $86.9 million related to our assets in the Texas Panhandle and $1.1 million related to onshore Gulf Coast properties. We recorded non-cash charges during the year ended 2014 of $5.5 million related to natural gas and oil properties in Mississippi, $18.5 million related to properties in West Texas and $4.0 million to fully impair our remaining oil and natural gas properties in North Texas. We recorded non-cash charges during the year ended 2013 of $7.0 million related to Gulf Coast onshore oil and gas properties. Also in 2013, we evaluated certain surface property we own which included a consideration for the potential sale of the assets and we recognized impairment charges of $741,000 in 2013. The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands): Year Ended December 31, 2015 2014 2013 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ 152,230 $ 590,174 $ 15,605 $ 28,024 $ 500 $ 7,012 Surface property ¾ ¾ ¾ ¾ 5,550 741 Fair Values - Reported The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2015 and 2014 (in thousands): December 31, 2015 December 31, 2014 Carrying Fair Carrying Fair Value Assets: Commodity swaps, collars and basis swaps $ 288,762 $ 288,762 $ 403,363 $ 403,363 Marketable securities (a) 62,376 62,376 68,454 68,454 Liabilities: Commodity swaps, collars and basis swaps (1,157 ) (1,157 ) ¾ ¾ Bank credit facility (b) (95,000 ) (95,000 ) (723,000 ) (723,000 ) Deferred compensation plan (c) (122,918 ) (122,918 ) (203,433 ) (203,433 ) 4.875% senior notes due 2025 (b) (750,000 ) (572,813 ) ¾ ¾ 6.75% senior subordinated notes due 2020 (b) ¾ ¾ (500,000 ) (523,125 ) 5.75% senior subordinated notes due 2021 (b) (500,000 ) (396,250 ) (500,000 ) (520,000 ) 5.00% senior subordinated notes due 2022 (b) (600,000 ) (447,000 ) (600,000 ) (601,500 ) 5.00% senior subordinated notes due 2023 (b) (750,000 ) (551,250 ) (750,000 ) (754,688 ) (a) (b) (c) The fair value of our deferred compensation plan is updated based on closing prices on the balance sheet date. 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.

Stock-based Compensation Plans

Stock-based Compensation Plans	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-based Compensation Plans	(12) Stock-based Compensation Plans Description of the Plans The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the compensation committee of the board of directors to grant, among other things, stock options, SARs, PSUs and restricted stock awards to employees. The 2005 Plan also allows us to provide equity compensation to our non-employee directors. The 2005 Plan was approved by stockholders in May 2005 and replaced our 1999 Stock Option Plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares 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 stockholders. After the approval of the 2005 Plan, no new grants have been made from the 1999 Stock Option Plan. In addition, our 2004 Non-Employee Director Stock Option Plan (the “Director Plan”) expired at the end of 2014. Any awards previously granted under the 1999 Stock Option Plan or the Director Plan continue to be exercisable in accordance with their original terms and conditions. Stock-Based Awards Prior to 2005, we granted stock options under our various stock option plans. Stock options represent the right to purchase shares of stock in the future at the fair value of the stock on the date of grant. Beginning in 2005, we began granting 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 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, we began granting restricted stock units under our equity-based stock compensation plan. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. In first quarter 2014, we began granting PSU awards. The number of shares to be issued is determined by our total shareholder return compared to the total shareholder return of a predetermined group of peer companies over the performance period. The PSU awards vest at the end of the three-year performance period. The grant date fair value of the PSU awards is determined using a Monte Carlo simulation and is recognized as stock-based compensation expense over the three-year performance 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 (by the trustee) and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either 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 amount 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. Total Stock-Based Compensation Expense Stock-based compensation expense represents amortization of restricted stock, PSUs and SARs grants. The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2015 (in thousands): 2015 2014 2013 Direct operating expense $ 2,780 $ 4,208 $ 2,755 Brokered natural gas and marketing expense 2,132 3,523 1,852 Exploration expense 2,985 4,569 4,025 General and administrative expense 49,687 55,382 55,737 Termination costs 217 2,999 ¾ Total $ 57,801 $ 70,681 $ 64,369 Unlike the other forms of stock-based compensation expense 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 and is reported as deferred compensation plan expense in the accompanying consolidated statement of operations. Stock-based compensation expense in the year ended December 31, 2014 includes $6.7 million of awards granted to our former executive chairman for his 2013 service while he was a Range officer, which were fully vested upon grant. In 2015, the tax deduction for stock-based compensation was less than the book stock-based compensation expense for equity compensation grants vested or exercised during the year. The tax effect of the deduction was recorded as a reduction to additional paid-in capital. For the years ended December 31, 2014 and 2013, 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. Performance Share Unit Awards The following is a summary of our non-vested PSU award activities: (a) Weighted Outstanding at December 31, 2013 — $ — Granted 227,929 86.14 Vested (b) (92,077 ) 86.23 Forfeited (1,511 ) 82.60 Outstanding at December 31, 2014 134,341 86.11 Granted 276,204 56.78 Vested ( c ) (143,094 ) 68.73 Forfeited (5,327 ) 82.60 Outstanding at December 31, 2015 262,124 $ 64.77 (a) These (b) (c) A Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of PSUs granted during the year ended December 31, 2015 and 2014: Year Ended December 31, 2015 2014 Risk-free interest rate 1.02 % 0.77 % Expected annual volatility 33 % 33 % Grant date fair value per unit $ 56.78 $ 86.14 We recorded PSU compensation expense of $8.7 million in the year ended December 31, 2015 compared to $7.9 million in the year ended December 31, 2014 and none in the same period of 2013. As of December 31, 2015, there was $15.7 million of unrecognized compensation related to PSU awards to be recognized over a weighted average period of 1.9 years. Restricted Stock Awards Equity Awards In 2015, we granted 588,000 restricted stock Equity Awards to employees which generally vest over a three-year period compared to 356,000 in 2014 and 402,000 in 2013. We recorded compensation expense for these awards of $23.8 million in the year ended December 31, 2015 compared to $28.1 million in 2014 and $19.7 million in 2013. As of December 31, 2015, there was $23.8 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.7 years. Restricted stock Equity Awards are not issued to employees until such time as they are vested and the employees do not have the option to receive cash. Liability Awards In 2015, we granted 343,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $55.92. This grant included 48,000 issued to non-employee directors which vest immediately and 295,000 to employees with vesting generally over a three-year period. In 2014, we granted 272,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $87.34. This grant included 64,000 issued to non-employee directors, which vest immediately and 208,000 to employees with vesting generally over a three-year period. In 2013, we granted 425,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $75.53. This grant included 18,000 issued to non-employee directors, which vest immediately, and 407,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $20.8 million in the year ended December 31, 2015 compared to $26.3 million in 2014 and $27.4 million in 2013. As of December 31, 2015, there was $18.1 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.8 years. The majority of all of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $8.3 million in 2015 compared to $16.0 million in 2014 and $20.7 million in 2013. A summary of the status of our non-vested restricted stock outstanding at December 31, 2015 is summarized below: Equity Awards Liability Awards Shares Weighted Shares Weighted Outstanding at December 31, 2012 349,156 $ 59.08 423,478 $ 58.91 Granted 402,053 71.26 424,809 75.53 Vested (315,535 ) 62.43 (437,570 ) 64.36 Forfeited (50,611 ) 65.29 (21,704 ) 57.31 Outstanding at December 31, 2013 385,063 68.24 389,013 71.02 Granted 356,194 84.87 272,052 87.34 Vested (354,237 ) 72.85 (356,413 ) 75.52 Forfeited (26,605 ) 75.66 (148 ) 77.35 Outstanding at December 31, 2014 360,415 79.60 304,504 80.33 Granted 587,711 52.29 343,397 55.92 Vested (480,253 ) 65.21 (330,870 ) 68.71 Forfeited (31,109 ) 64.73 (8,294 ) 74.22 Outstanding at December 31, 2015 436,764 $ 59.74 308,737 $ 65.80 Stock Appreciation Right Awards During 2014 and 2013, we granted SARs to officers, non-officers employees and directors. Information with respect to our SARs activities is summarized below. During 2014, we granted SARs to our former executive chairman in conjunction with his retirement from Range as an employee. Shares Weighted Outstanding at December 31, 2012 3,433,362 $ 52.52 Granted 470,617 75.82 Exercised (1,269,323 ) 53.24 Expired/forfeited (52,582 ) 53.56 Outstanding at December 31, 2013 2,582,074 56.36 Granted 1,104 81.74 Exercised (616,563 ) 45.45 Expired/forfeited (66 ) 46.44 Outstanding at December 31, 2014 1,966,549 59.80 Exercised (427,598 ) 45.67 Expired/forfeited (27,974 ) 63.10 Outstanding at December 31, 2015 1,510,977 $ 63.73 The following table shows information with respect to SARs outstanding and exercisable at December 31, 2015: Outstanding Exercisable Range of Exercise Prices Shares Weighted Weighted Average Exercise Price Shares Weighted Average Exercise Price $ 40.00–$ 49.99 112,769 0.13 $ 49.18 112,769 $ 49.18 50.00–59.99 355,052 0.38 52.35 355,052 52.35 60.00–69.99 602,926 1.34 64.19 602,926 64.19 70.00–79.99 438,330 2.28 75.99 301,641 76.08 80.00–81.15 1,900 2.69 81.15 1,900 81.15 Total 1,510,977 1.30 $ 63.73 1,374,288 $ 62.53 The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below: 2014 2013 Weighted average exercise price per share $ 81.74 $ 75.82 Expected annual dividend yield 0.20 % 0.21 % Expected life in years 4.3 3.7 Expected volatility 33 % 35 % Risk-free interest rate 1.4 % 0.6 % Weighted average grant date fair value per share $ 23.17 $ 20.20 The expected 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 at the time of grant) of SARs exercised during the year ended December 31, 2015 was $5.4 million compared to $27.1 million in 2014 and $30.3 million in 2013. As of December 31, 2015, there was no aggregate intrinsic value for any of the awards exercisable or awards outstanding. The weighted average remaining contractual life of awards exercisable was 1.2 years. As of December 31, 2015, the number of fully vested awards and the awards expected to vest was 1.5 million shares. The weighted average exercise price and weighted average remaining contractual life of these awards were $63.72 and 1.3 years. As of December 31, 2015, unrecognized compensation cost related to the awards was $701,000, which is expected to be recognized over a weighted average period of 0.4 years. 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. We match up to 6% of salary in cash and vesting of those contributions is immediate. In 2015, we contributed $6.1 million to the 401(k) Plan compared to $5.8 million in 2014. 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 gain of $77.6 million in 2015 compared to a gain of $74.6 million in 2014 and a loss of $55.3 million in 2013. The Rabbi Trust held 2.8 million shares (2.5 million of vested shares) of Range stock at both December 31, 2015 and 2014.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	(13) Supplemental Cash Flow Information Year Ended December 31, 2015 2014 2013 (in thousands) Net cash provided from operating activities included: Income taxes paid to (refunded from) taxing authorities $ 100 $ (156 ) $ (347 ) Interest paid 168,826 165,530 159,137 Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 22,184 $ 56,822 $ 76,373 (Decrease) increase in accrued capital expenditures (225,455 ) 150,604 27,079

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	(14) Commitments and Contingencies Litigation We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation. Lease Commitments We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $15.9 million in 2015 compared to $13.3 million in 2014 and $13.1 million in 2013. 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 2016 $ 11,819 2017 10,014 2018 8,902 2019 7,264 2020 7,238 Thereafter 29,258 $ 74,495 Transportation and Gathering Contracts We have entered into 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, 2015, future minimum transportation and gathering fees under our commitments are as follows (in thousands): Transportation (a) 2016 $ 407,046 2017 401,517 2018 366,914 2019 366,562 2020 359,595 Thereafter 1,748,559 $ 3,650,193 (a) In addition to the amounts included in the above table, we have entered into additional agreements which are contingent on certain pipeline and gathering line modifications and/or construction. These agreements range between six and twenty year terms and are expected to begin in 2016 and 2017. Based on these contracts, we will have additional transportation obligations for natural gas volumes of 2.0 bcf per day until 2026, declining to 1.3 bcf per day through 2032 and 400,000 mcf per day until 2037. We also have gathering obligations which begin in 2017 of up to 400,000 mcf per day through 2032. Beginning in 2016, we also have transportation obligations for ethane volumes of 20,000 bbls per day and propane volumes of 20,000 bbls per day through the end of 2031. Delivery Commitments We have various volume delivery commitments that are primarily related to our Marcellus Shale and Oklahoma and Texas areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2015, our delivery commitments through 2028 were as follows: Year Ending December 31, Natural Gas Ethane and Propane (bbls per day) 2016 405,126 40,000 2017 241,301 40,000 2018 — 40,000 2019 — 20,000 2020 — 20,000 2021 — 20,000 2022 ¾ — 15,000 In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2033 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are contingent upon pipeline construction and/or modification, are for 20,000 bbls per day starting in 2016, increasing to 30,000 bbls per day in 2018 and 45,000 bbls per day in 2020 through the end of the term. In addition, we have agreements in place to deliver natural gas volumes from our Marcellus Shale wells, which are also contingent upon pipeline construction and/or modification, for 50,000 mcf per day starting in late 2017, increasing to 200,000 mcf per day in early 2019 and 300,000 mcf per day in late 2019. Other We also 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 are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2015
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	(15) Equity Method Investments We accounted for our investments in entities over which we had significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, we recorded our proportionate share of net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. We also evaluated 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 include sustained operating losses by the investee or long-term negative changes in the investee’s industry. As of June 2014, we no longer have equity method investments. 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. In September 2013, we sold our equity method investment in Whipstock for proceeds of $7.0 million and recognized a gain of $4.4 million. 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 was 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 formation, we contributed cash of $94.7 million for a 50% membership interest in NGLLC. NGLLC followed a calendar year basis of financial reporting consistent with us and our equity in NGLLC earnings from the acquisition date is included in brokered natural gas, marketing and other revenue in the accompanying consolidated statements of operations for 2014 and 2013. In 2014, we received partnership distributions of $7.0 million compared to $9.0 million in 2013. In determining our proportionate share of the net earnings of NGLLC, certain adjustments were 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 six months ended June 30, 2014, our equity in losses of NGLLC of $277,000 reflects a reduction of $3.1 million to eliminate the profit on gathering and transportation fees charged to us. For the year ended December 31, 2013, our equity in losses of NGLLC of $146,000 reflects a reduction of $7.7 million to eliminate the profit on the gathering and transportation fees charged to us. On June 16, 2014, as part of our Conger Exchange, we acquired the remaining 50% interest in NGLLC held by EQT. See Note 3 for additional information. As of June 2014, we consolidated these operations into our consolidated financial statements.

Office Closing and Exit Costs

Office Closing and Exit Costs	12 Months Ended
	Dec. 31, 2015
Restructuring And Related Activities [Abstract]
Office Closing and Exit Costs	( 16) Office Closing and Exit Costs In first quarter 2015, we announced the closing of our Oklahoma City administrative and operational office in order to lower our general and administrative expenses, due in part to the impact of lower commodity prices on our operations. In fourth quarter 2014, we initially accrued an estimated $8.4 million of termination costs relating to the closure of this office as it was probable of occurring. In early 2015, those plans and personnel involved were finalized which resulted in additional accruals in 2015 for severance and other personnel costs of $275,000, additional accelerated vesting of stock-based compensation of $948,000 and $3.1 million of building lease costs. In addition, the year ended December 31, 2015 includes additional accruals for severance of $11.4 million and a gain of $731,000 of accelerated vesting of stock-based compensation related to the sale of our Virginia and West Virginia properties which closed on December 30, 2015 and additional reductions in our work force due to the lower commodity price environment. The following table details the accrued liability as of December 31, 2015 and December 31, 2014 (in thousands): 2015 2014 Beginning balance $ 5,372 $ — Accrued severance costs 11,706 5,372 Accrued building rent 3,147 — Payments (8,595 ) — Ending balance $ 11,630 $ 5,372 The following summarizes our termination costs for the year ended December 31, 2015 and December 31, 2014 (in thousands): 2015 2014 Severance costs $ 11,706 $ 5,372 Building lease 3,147 — Stock-based compensation 217 2,999 Total termination costs $ 15,070 $ 8,371

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data (Unaudited)	(17) Selected Quarterly Financial Data (Unaudited) The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Fourth quarter 2015 includes a loss of $407.7 million from the sale of our Virginia and West Virginia oil and gas properties and impairment expense of $87.9 million related to oil and gas properties in the Texas Panhandle and South Texas. Third quarter 2015 includes impairment expense of $502.2 million related to our Northern Oklahoma and legacy shallow Northwest Pennsylvania assets. Second quarter 2014 includes a gain of $280.1 million from the Conger Exchange (in thousands, except per share data): 2015 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 325,483 $ 258,053 $ 252,065 $ 254,043 $ 1,089,644 Derivative fair value income (loss) 122,839 (34,791 ) 202,004 126,312 416,364 Brokered natural gas, marketing and other 14,485 21,339 25,864 30,372 92,060 Total revenue and other income 462,807 244,601 479,933 410,727 1,598,068 Costs and expenses: Direct operating 37,137 34,780 35,058 29,388 136,363 Transportation, gathering and compression 89,426 95,198 99,634 112,481 396,739 Production and ad valorem taxes 9,928 9,242 7,336 7,354 33,860 Brokered natural gas and marketing 21,562 27,031 32,331 34,942 115,866 Exploration 7,886 5,025 4,235 4,260 21,406 Abandonment and impairment of unproved properties 11,491 12,330 12,366 11,432 47,619 General and administrative 48,329 55,964 46,178 43,544 194,015 Termination costs 5,950 417 (77 ) 8,780 15,070 Deferred compensation plan (5,624 ) (7,282 ) (43,705 ) (21,016 ) (77,627 ) Interest 39,207 43,479 42,904 40,849 166,439 Loss on early extinguishment of debt — — 22,495 — 22,495 Depletion, depreciation and amortization 147,290 151,895 153,993 127,977 581,155 Impairment of proved properties and other — — 502,233 87,941 590,174 Loss (gain) on sale of assets 175 (2,909 ) 681 408,909 406,856 Total costs and expenses 412,757 425,170 915,662 896,841 2,650,430 Income (loss) before income taxes 50,050 (180,569 ) (435,729 ) (486,114 ) (1,052,362 ) Income tax expense (benefit): Current — — — 29 29 Deferred 22,366 (61,975 ) (134,781 ) (164,316 ) (338,706 ) 22,366 (61,975 ) (134,781 ) (164,287 ) (338,677 ) Net income (loss) $ 27,684 $ (118,594 ) $ (300,948 ) $ (321,827 ) $ (713,685 ) Net income (loss) per common share: Basic $ 0.16 $ (0.71 ) $ (1.81 ) $ (1.93 ) $ (4.29 ) Diluted $ 0.16 $ (0.71 ) $ (1.81 ) $ (1.93 ) $ (4.29 ) 2014 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 572,017 $ 477,517 $ 446,067 $ 416,388 $ 1,911,989 Derivative fair value (loss) income (146,850 ) (24,109 ) 142,057 412,422 383,520 Brokered natural gas, marketing and other 32,528 30,052 28,324 39,644 130,548 Total revenue and other income 457,695 483,460 616,448 868,454 2,426,057 Costs and expenses: Direct operating 39,795 34,935 37,792 37,961 150,483 Transportation, gathering and compression 74,161 76,809 84,777 89,542 325,289 Production and ad valorem taxes 11,678 10,844 10,110 11,923 44,555 Brokered natural gas and marketing 34,129 34,775 28,706 32,370 129,980 Exploration 14,846 13,621 11,443 23,638 63,548 Abandonment and impairment of unproved properties 9,995 9,332 13,444 14,308 47,079 General and administrative 49,212 56,888 54,963 52,363 213,426 Termination costs — — — 8,371 8,371 Deferred compensation plan (2,035 ) 10,519 (46,198 ) (36,836 ) (74,550 ) Interest 45,401 45,488 39,188 38,900 168,977 Loss on early extinguishment of debt — 24,596 — — 24,596 Depletion, depreciation and amortization 128,682 133,361 142,450 146,539 551,032 Impairment of proved properties and other — 24,991 — 3,033 28,024 Loss (gain) on sale of assets 353 (282,064 ) (167 ) (3,760 ) (285,638 ) Total costs and expenses 406,217 194,095 376,508 418,352 1,395,172 Income before income taxes 51,478 289,365 239,940 450,102 1,030,885 Income tax expense (benefit): Current 6 (1 ) — (4 ) 1 Deferred 18,951 117,977 93,522 166,052 396,502 18,957 117,976 93,522 166,048 396,503 Net income $ 32,521 $ 171,389 $ 146,418 $ 284,054 $ 634,382 Net income per common share: Basic $ 0.20 $ 1.04 $ 0.87 $ 1.68 $ 3.81 Diluted $ 0.20 $ 1.04 $ 0.86 $ 1.68 $ 3.79

Supplemental Information on Nat

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)	(18) Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) Our natural gas 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, 2015 2014 2013 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 8,047,181 $ 9,624,725 $ 8,225,859 Unproved properties 949,155 943,246 807,022 Total 8,996,336 10,567,971 9,032,881 Accumulated depreciation, depletion and amortization (2,635,031 ) (2,590,398 ) (2,274,444 ) Net capitalized costs $ 6,361,305 $ 7,977,573 $ 6,758,437 (a) Costs Incurred for Property Acquisition, Exploration (a) December 31, 2015 2014 2013 (in thousands) Acquisitions (b) $ ¾ $ 404,252 $ ¾ Acreage purchases 73,025 226,475 137,538 Development 708,268 1,119,896 938,668 Exploration: Drilling 87,505 180,925 189,742 Expense 18,421 58,979 60,384 Stock-based compensation expense 2,985 4,569 4,025 Gas gathering facilities: Development 13,337 13,137 47,086 Subtotal 903,541 2,008,233 1,377,443 Asset retirement obligations 22,184 56,822 76,373 Total costs incurred $ 925,725 $ 2,065,055 $ 1,453,816 (a) (b) Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) Reserves of natural gas, NGLs, 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, production taxes and other economic factors. Reserve Audit All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2015, the following independent petroleum consultant conducted an audit of our reserves: Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2015, our consultant collectively audited approximately 94% of our proved reserves. A copy of the summary reserve reports prepared by our independent petroleum consultant is included as exhibits to this Annual Report on Form 10-K. The technical person at our independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meets 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 during the reserves audit process. Throughout the year, our technical team meets periodically with representatives 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 significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest, natural gas, NGLs 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 identified reserve differences. The reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared lease-by-lease, field-by-field or area-by-area basis, some of our estimates may be greater and some may be less than the estimates of our reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis. Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum 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 Chairman, 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 and has more than thirty-five years of engineering experience in the oil and gas industry. 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, NGLs, 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 each location is scheduled to be drilled within five years from the date it was booked as proved reserves, 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, 2015 to estimate reserve information were $35.07 per barrel of oil, $11.74 per barrel of NGLs and $2.07 per mcf for gas using a benchmark (NYMEX) of $50.13 per barrel and $2.59 per Mmbtu. The average realized prices used at December 31, 2014 to estimate reserve information were $79.04 per barrel of oil, $27.20 per barrel of NGLs and $4.14 per mcf for gas, using a benchmark (NYMEX) of $94.42 per barrel and $4.35 per Mmbtu. The average realized prices used at December 31, 2013 to estimate reserve information were $86.66 per barrel of oil, $25.93 per barrel of NGLs and $3.75 per mcf for gas, using a benchmark (NYMEX) of $97.33 per barrel and $3.67 per Mmbtu. Natural Gas NGLs Crude Oil and Condensate Natural Gas (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: Balance, December 31, 2012 4,792,676 240,399 45,082 6,505,570 Revisions 384,825 7,743 2,935 448,898 Extensions, discoveries and additions 853,746 135,810 10,723 1,732,944 Purchases ¾ ¾ ¾ ¾ Property sales (101,074 ) (286 ) (6,553 ) (142,116 ) Production (264,528 ) (9,254 ) (3,827 ) (343,022 ) Balance, December 31, 2013 5,665,645 374,412 48,360 8,202,274 Revisions (30,566 ) 19,716 515 90,822 Extensions, discoveries and additions 1,393,108 154,664 12,936 2,398,709 Purchases 262,813 ¾ ¾ 262,813 Property sales (81,238 ) (14,064 ) (9,083 ) (220,122 ) Production (286,926 ) (18,821 ) (4,070 ) (424,267 ) Balance, December 31, 2014 6,922,836 515,907 48,658 10,310,229 Revisions (340,286 ) 17,717 3,804 (211,163 ) Extensions, discoveries and additions 1,017,956 36,308 4,924 1,265,348 Purchases ¾ ¾ ¾ ¾ Property sales (960,122 ) (441 ) (109 ) (963,423 ) Production (362,687 ) (20,356 ) (4,084 ) (509,328 ) Balance, December 31, 2015 6,277,697 549,135 53,193 9,891,663 Proved developed reserves: December 31, 2013 2,797,483 206,477 26,054 4,192,666 December 31, 2014 3,583,051 270,271 24,180 5,349,761 December 31, 2015 3,376,165 309,306 31,679 5,422,075 Proved undeveloped reserves: December 31, 2013 2,868,162 167,935 22,306 4,009,608 December 31, 2014 3,339,785 245,636 24,478 4,960,468 December 31, 2015 2,901,533 239,828 21,514 4,469,588 (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 indicative of the relationship of oil and natural gas prices. During 2015, we added approximately 1.3 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 80% of the 2015 reserve additions are attributable to natural gas. Included in 2015 proved reserves is a total of 292.8 Mmbbls of ethane reserves (1,296 Bcfe) in the Marcellus Shale. Revisions of previous estimates of a negative 211 Bcfe includes positive performance revisions and improved recoveries of 781.0 Bcf primarily from our Marcellus Shale natural gas properties more than offset by negative price revisions and 1.2 Tcfe reclassified to unproved because of lower future capital spending in response to lower commodity prices. During 2014, we added approximately 2.4 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 58% of 2014 reserve additions were attributable to natural gas. Included in 2014 proved reserves is a total of 1,170 Bcfe of ethane reserves (264.3 Mmbbls) in the Marcellus Shale. Revisions of previous estimates of a positive 91 Bcfe includes positive performance revisions, improved recoveries of 449.6 Bcfe primarily from our Marcellus Shale natural gas properties and positive price revisions are somewhat offset by reserves of 611 Bcfe reclassified to unproved as we continue to see success from drilling longer laterals, increasing the number of frac stages and better lateral targeting which caused some previously planned wells to not be drilled within the original five-year development horizon. During 2013, we added approximately 1.7 Tcfe of proved reserves from drilling activities and valuation of proved areas primarily in the Marcellus Shale. Approximately 49% of 2013 reserve additions were attributable to natural gas. Also, included in 2013 proved reserves is a total of 676 Bcfe of ethane reserves (155.8 Mmbbls) in the Marcellus Shale. Revisions of previous estimates of a positive 449 Bcfe includes positive performance revisions and improved recoveries of 630.3 Bcfe primarily from our Marcellus Shale natural gas properties and positive pricing revisions, somewhat offset by reserves reclassified to unproved because of a slower pace of development activity beyond the five-year development horizon. The following details the changes in proved undeveloped reserves for 2015 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2014 4,960,468 Undeveloped reserves transferred to developed (762,936 ) Revisions (a) (441,874 ) Purchases/(sales) (201,809 ) Extension and discoveries 915,739 Ending proved undeveloped reserves at December 31, 2015 4,469,588 (a) Approximately $398.8 million was spent during 2015 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $435.6 million in 2016, $509.4 billion in 2017 and $471.6 million in 2018. As of December 31, 2015, we have no proved undeveloped well locations that are scheduled to be drilled more than five years from their original date of booking. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2020. 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, crude oil and condensate 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, crude oil and condensate, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: 1. Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions. 2. For the years ended 2015, 2014 and 2013, 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. 3. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves. 4. The resulting future net cash flows are discounted to present value by applying a discount rate of 10%. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, 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, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives 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, 2015 2014 (in thousands) Future cash inflows $ 21,290,873 $ 46,507,646 Future costs: Production (10,411,360 ) (15,239,210 ) Development (a) (2,213,582 ) (4,275,693 ) Future net cash flows before income taxes 8,665,931 26,992,743 Future income tax expense (2,007,794 ) (8,900,383 ) Total future net cash flows before 10% discount 6,658,137 18,092,360 10% annual discount (3,932,274 ) (10,499,333 ) Standardized measure of discounted future net cash flows $ 2,725,863 $ 7,593,027 (a) The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2015 2014 2013 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ (7,231,629 ) $ 5,069 $ 2,172,704 Revisions in quantities (868,886 ) 102,760 513,168 Changes in future development and abandonment costs 359,540 (407,688 ) (275,468 ) Net change in income taxes 2,173,904 (441,935 ) (1,299,227 ) Accretion of discount 1,007,027 789,754 395,989 Purchases of reserves in place ¾ 297,358 ¾ Additions to proved reserves from extensions, discoveries and improved recovery 486,478 2,713,999 1,981,054 Natural gas, NGLs and oil sales, net of production costs (522,682 ) (1,391,663 ) (1,286,103 ) Development costs incurred during the period 1,033,539 755,384 462,862 Sales of reserves in place (1,050,237 ) (249,055 ) (162,463 ) Timing and other (254,218 ) (443,187 ) 135,910 Net change for the year (4,867,164 ) 1,730,796 2,638,426 Beginning of year 7,593,027 5,862,231 3,223,805 End of year $ 2,725,863 $ 7,593,027 $ 5,862,231

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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 brokered natural gas, marketing and other revenues in the accompanying consolidated statements of operations. As of June 2014, we no longer have equity method investments. All material intercompany balances and transactions have been eliminated.
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 as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. 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 to the current year presentation. This includes reclassification of deferred income tax balances included in the consolidated balance sheets from current to long-term and the reclassification of debt issuance costs included in the consolidated balance sheets from other assets to offset our debt balances. These reclassifications were made as a result of our adoption of new accounting pronouncements and did not impact our net loss, stockholders’ equity or cash flows.
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 in the United States. We consider our gathering, processing and marketing functions as integral 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 a geographical or 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.
Revenue Recognition, Accounts Receivable and Gas Imbalances	Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is reasonably assured. 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. We are reporting our gathering and transportation costs in accordance with Accounting Standards Code 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 receive from the purchaser. For the sale of our NGLs, we receive a price from the purchaser (which is net of processing costs) that is recorded in revenue at the net price we receive. Under the other type of agreement, we sell natural gas or oil at a specific delivery point, pay transportation, gathering and compression expenses to a third party and receive proceeds from the purchaser with no 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. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby Range or the counterparty takes titles to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. In 2013, we also included purchased (and sold) natural gas which was used to blend our rich residue gas from the Southwest Marcellus Shale. In 2014, we also included additional broker revenues and broker expenses from the release of transportation capacity where we had taken firm transportation ahead of our production volumes. Our net brokered margin was a loss of $2.7 million in 2015 compared to a gain of $9.4 million in 2014 and a loss of $5.7 million in 2013. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $5.0 million at December 31, 2015 compared to $2.7 million at December 31, 2014. We recorded bad debt expense of $2.3 million in the year ended December 31, 2015 compared to $250,000 in both the years ended December 31, 2014 and 2013. Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. Imbalances are not significant in the periods presented.
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. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts are classified as financing activities on the consolidated statements of cash flows.
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 include equity securities and money market instruments.
Inventory	Inventory Inventories were comprised of $20.8 million of materials and supplies at December 31, 2015 compared to $11.8 million at December 31, 2014. Inventories consist primarily of tubular goods and equipment 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 material and supplies inventory is primarily acquired for use in future drilling operations or repair operations. At December 31, 2015, we also had commodity inventory of $4.8 million, compared to $2.0 million at December 31, 2014, which is carried at lower of average cost or market, on a first-in, first-out basis. Commodity inventory at December 31, 2015 consists of natural gas and NGLs held in storage or as line fill in pipelines.
Natural Gas and Oil Properties	Natural Gas and Oil Properties Property Acquisition Costs . We use 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. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended exploratory well costs, see Note 6. Depreciation, Depletion and Amortization . Depreciation, depletion and amortization of proved producing properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, 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 at other times during the year when circumstances indicate there has been a significant change in reserves or costs. Impairments . Our proved natural gas and oil properties are reviewed for impairment annually and 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 impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. 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, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. 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 undiscounted 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 11. 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 $949.2 million as of December 31, 2015 compared to $943.2 million in 2014. We have recorded abandonment and impairment expense related to unproved properties of $47.6 million in the year ended December 31, 2015 compared to $47.1 million in 2014 and $51.9 million in 2013. Dispositions . Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base 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. For additional information regarding our dispositions, see Note 3. Acquisitions . Acquisitions of proved properties are accounted for as business combinations and, accordingly, the results of operations are included in the accompanying consolidated 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.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and 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 three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $11.9 million in the year ended December 31, 2015 compared to $12.9 million in the year ended December 31, 2014 and $13.2 million in the year ended December 31, 2013.
Other Assets	Other Assets Other assets at December 31, 2015 include $62.4 million of marketable securities held in our deferred compensation plans and $10.6 million of other investments including surface acreage. Other assets at December 31, 2014 include $68.5 million of marketable securities held in our deferred compensation plans and $10.3 million of other investments including surface acreage.
Stock-based Compensation Arrangements	Stock-based Compensation Arrangements The fair value of performance share unit awards (“PSUs”) is estimated on the date of grant using a Monte Carlo simulation method. A Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant. The fair value of stock-settled stock appreciation rights (“SARs”) is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The models employ 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 awards. 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. The majority of our Liability Awards are deposited in our deferred compensation plan 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 consolidated statements 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. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm, when they are governed by master netting agreements. 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. Effective March 1, 2013, we elected to discontinue hedge accounting prospectively. For more information, see Note 10. The effective portions of the discontinued deferred hedges as of March 1, 2013 were included in accumulated other comprehensive income (“AOCI”) and were transferred to earnings during the same periods in which the forecasted transactions were recognized in earnings. During 2014, the remaining AOCI hedging gains were transferred to earnings. Since discontinuing hedge accounting, all realized and unrealized gains and losses on 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 in the accompanying consolidated statements of operations. At times, we have also entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. We have not acquired any hedges through a business combination and have not modified any existing derivative contracts.
Concentrations of Credit Risk	Concentrations of Credit Risk As of December 31, 2015, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and are generally unsecured. To manage risks of collecting accounts receivable, we monitor our counterparties financial strength and/or credit ratings and where we deem necessary, obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $5.0 million at December 31, 2015 compared to $2.7 million at December 31, 2014. For the year ended December 31, 2015, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. For both of the years ended December 31, 2014 and December 31, 2013, we had four 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. We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set off receivables owed under all derivative contracts against payables from other agreements with that counterparty. None of our derivative contracts have margin requirements or collateral provisions that would require us to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2015, our derivative counterparties included seventeen financial institutions and commodity traders of which all but four are secured lenders in our bank credit facility. At December 31, 2015, our net derivative asset includes a receivable from the counterparties not included in our bank credit facility totaling $11.5 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance.
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 of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 8 for additional information.
Environmental Costs	Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.
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 may include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. We do not recognize a deferred tax asset for excess tax benefits on equity compensation that have not been realized due to our net operating loss tax position for federal or state tax purposes. All deferred taxes are classified as long-term on the balance sheet.
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive The following details the components of AOCI and related tax effects for the two years ended December 31, 2014 (in thousands). Amounts included in AOCI exclusively relate to our derivative activity. See Note 10 for additional information on the discontinuance of hedge accounting. Gross Tax Effect Net of Tax Accumulated other comprehensive income at December 31, 2012 $ 137,555 $ (53,646 ) $ 83,909 Contract settlements reclassified to income (120,443 ) 46,973 (73,470 ) Change in unrealized deferred hedging gains (6,890 ) 2,687 (4,203 ) Accumulated other comprehensive income at December 31, 2013 10,222 (3,986 ) 6,236 Contract settlements reclassified to income (10,222 ) 3,986 (6,236 ) Accumulated other comprehensive income at December 31, 2014 $ ¾ $ ¾ $ ¾
Recently Adopted	New Accounting Pronouncements Recently Adopted In April 2014, an accounting standards update was issued that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other material disposal transactions that do not meet the revised definition of a discontinued operation. Under the updated standard, a disposal of a component or group of components of an entity is required to be reported as discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component or group of components of the entity (1) has been disposed of by a sale, (2) has been disposed of other than by sale or (3) is classified as held for sale. This accounting standards update is effective for annual periods beginning on or after December 15, 2014 and is applied prospectively. Early adoption was permitted but only for disposals (or classifications that are held for sale) that had not been reported in financial statements previously issued or available for use. We adopted this new standard in first quarter 2014 and, as a result, the Conger Exchange defined and described in more detail below, was not reported as a discontinued operation. In April 2015, an accounting standards update was issued that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for the reporting period beginning on January 1, 2016 with early adoption permitted. As of December 31, 2015, we have adopted this standard retrospectively and have accounted for the debt issuance costs as a reduction of the associated debt liability. Previously, these costs were reported in other long-term assets. We reclassified $9.8 million from other long-term assets to bank debt and $32.4 million from other long-term assets to subordinated notes as of December 31, 2014. This adoption only affected our consolidated balance sheet and did not have an impact on our consolidated results of operations or cash flows. In November 2015, an accounting standards update was issued which requires entities to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This standard is effective for the reporting period beginning in January 1, 2017 with early adoption permitted. As of December 31, 2015, we have adopted this standard retrospectively and have reclassified our December 31, 2014 current deferred tax assets and liabilities into non-current deferred tax assets and liabilities. We reclassified $115.6 million current deferred tax liabilities into non-current deferred tax liabilities as of December 31, 2014. This adoption only affected our consolidated balance sheets and did not have an impact on our consolidated results of operations or cash flows.
Accounting Pronouncements Not Yet Adopted	Accounting Pronouncements Not Yet Adopted In May 2014, an accounting standards update was issued that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in first quarter 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted with an effective date no earlier than first quarter 2017. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows. In August 2014, an accounting standards update was issued that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. This standard is effective for us in first quarter 2017 and early adoption is permitted. We do not expect the adoption of this standard to have a significant impact on our consolidated results of operations, financial position or cash flows.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Accumulated Other Comprehensive Income	The following details the components of AOCI and related tax effects for the two years ended December 31, 2014 (in thousands). Amounts included in AOCI exclusively relate to our derivative activity. See Note 10 for additional information on the discontinuance of hedge accounting. Gross Tax Effect Net of Tax Accumulated other comprehensive income at December 31, 2012 $ 137,555 $ (53,646 ) $ 83,909 Contract settlements reclassified to income (120,443 ) 46,973 (73,470 ) Change in unrealized deferred hedging gains (6,890 ) 2,687 (4,203 ) Accumulated other comprehensive income at December 31, 2013 10,222 (3,986 ) 6,236 Contract settlements reclassified to income (10,222 ) 3,986 (6,236 ) Accumulated other comprehensive income at December 31, 2014 $ ¾ $ ¾ $ ¾

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax	Our income tax benefit was $338.7 million for the year ended December 31, 2015 compared to income tax expense of $396.5 million in 2014 and income tax expense of $33.9 million in 2013. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2015 2014 2013 Federal statutory tax rate 35.0 % 35.0 % 35.0 % State 4.3 3.1 (2.3 ) State apportionment rate change (0.2 ) (0.2 ) (14.9 ) Non-deductible executive compensation (0.1 ) 0.2 0.7 Valuation allowances (6.8 ) 0.2 3.5 Other ¾ 0.2 0.6 Consolidated effective tax rate 32.2 % 38.5 % 22.6 %
Income Tax (Benefit) Expense Attributable to Income Before Income Taxes	Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands): 2015 2014 2013 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ ¾ $ (328,257 ) $ (328,257 ) $ ¾ $ 361,152 $ 361,152 $ ¾ $ 58,527 $ 58,527 U.S. state and local 29 (10,449 ) (10,420 ) 1 35,350 35,351 (143 ) (24,527 ) (24,670 ) Total $ 29 $ (338,706 ) $ (338,677 ) $ 1 $ 396,502 $ 396,503 $ (143 ) $ 34,000 $ 33,857
Significant Components of Deferred Tax Assets and Liabilities	Significant components of deferred tax assets and liabilities are as follows: December 31, 2015 2014 (in thousands) Deferred tax assets: Net operating loss carryforward $ 173,503 $ 176,812 Deferred compensation 45,413 73,942 Equity compensation 25,940 25,833 AMT credits and other credits 4,437 4,447 Asset retirement obligation 101,142 109,808 Cumulative mark-to-market loss ¾ 649 Other 10,163 10,908 Valuation allowances: Federal (42,500 ) ¾ State, net of federal benefit (41,516 ) (8,800 ) Deferred compensation plans and other (3,607 ) (7,799 ) Total deferred tax assets 272,975 385,800 Deferred tax liabilities: Depreciation, depletion and investments (940,482 ) (1,342,038 ) Cumulative mark-to-market gain (109,845 ) (154,183 ) Other (595 ) (2,660 ) Total deferred tax liabilities (1,050,922 ) (1,498,881 ) Net deferred tax liability $ (777,947 ) $ (1,113,081 )

Net (Loss) Income Per Common 31

Net (Loss) Income Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Computations of Basic and Diluted (Loss) Income Per Common Share	Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (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 stockholders (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 net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts): Year Ended December 31, 2015 2014 2013 Net (loss) income, as reported $ (713,685 ) $ 634,382 $ 115,722 Participating basic earnings (a) (450 ) (10,725 ) (1,975 ) Basic net (loss) income attributed to common stockholders (714,135 ) 623,657 113,747 Reallocation of participating earnings (a) ¾ 48 9 Diluted net (loss) income attributed to common stockholders $ (714,135 ) $ 623,705 $ 113,756 Net (loss) income per common share: Basic $ (4.29 ) $ 3.81 $ 0.71 Diluted $ (4.29 ) $ 3.79 $ 0.70 (a) Restricted stock Liability 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.
Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding	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, 2015 2014 2013 Denominator: Weighted average common shares outstanding – basic 166,389 163,625 160,438 Effect of dilutive securities: Director and employee SARs and restricted stock Equity Awards ¾ 778 969 Weighted average common shares outstanding – diluted 166,389 164,403 161,407

Suspended Exploratory Well Co32

Suspended Exploratory Well Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Suspended Exploratory Well Costs	The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015, 2014 and 2013 (in thousands, except for number of projects): 2015 2014 2013 Balance at beginning of period $ 2,996 $ 6,964 $ 57,360 Additions to capitalized exploratory well costs pending the determination of proved reserves 1,165 18,747 39,832 Reclassifications to wells, facilities and equipment based on determination of proved reserves ¾ (15,735 ) (84,840 ) Capitalized exploratory well costs charged to expense ¾ (6,980 ) (5,388 ) Balance at end of period 4,161 2,996 6,964 Less exploratory well costs that have been capitalized for a period of one year or less (1,165) (2,996 ) ¾ Capitalized exploratory well costs that have been capitalized for a period greater than one year $ 2,996 $ ¾ $ 6,964 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year 1 ¾ 1
Aging of Capitalized Exploratory Well Costs Suspended More Than One Year	The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of December 31, 2015 (in thousands): Total 2015 2014 Capitalized exploratory well costs that have been suspended for more than one year $ 2,996 $ ¾ $ 2,996

Indebtedness (Tables)

Indebtedness (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt Outstanding	We had the following debt outstanding as of the dates shown below which are net of debt issuance costs (bank debt interest rate at December 31, 2015 is shown parenthetically) (in thousands). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2015, 2014, and 2013. December 31, 2015 2014 Bank debt (1.8%), net of unamortized debt issuance costs of $8,573 and $9,779 $ 86,427 $ 713,221 Senior notes: 4.875% senior notes due 2025, net of unamortized debt issuance costs of $11,899 738,101 ¾ Senior subordinated notes: 6.75% senior subordinated notes due 2020, net of unamortized debt issuance costs of $6,157 ¾ 493,843 5.75% senior subordinated notes due 2021, net of unamortized debt issuance costs of $5,905 and $6,803 494,095 493,197 5.00% senior subordinated notes due 2022, net of unamortized debt issuance costs of $7,777 and $8,820 592,223 591,180 5.00% senior subordinated notes due 2023, net of unamortized debt issuance costs of $9,543 and $10,617 740,457 739,383 Total debt $ 2,651,303 $ 3,030,824
Schedule for Long-Term Debt Outstanding	The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2015 (in thousands): Year Ended 2016 $ — 2017 — 2018 — 2019 95,000 2020 — Thereafter 2,600,000 $ 2,695,000

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Our asset retirement obligations primarily represent the present value of the estimated 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 as of December 31, 2015 and 2014 are as follows (in thousands): 2015 2014 Beginning of period $ 287,463 $ 230,077 Liabilities incurred 4,595 8,602 Acquisitions 1,584 11,927 Liability released ¾ (8,309 ) Liabilities settled (18,828 ) (4,442 ) Disposition of wells (45,845 ) (13,951 ) Accretion expense 19,163 15,226 Change in estimate 16,005 48,333 End of period 264,137 287,463 Less current portion (15,071 ) (15,067 ) Long-term asset retirement obligations $ 249,066 $ 272,396

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
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 2013: Year Ended December 31, 2015 2014 2013 Beginning balance 168,628,177 163,342,894 162,514,098 Equity offering − 4,560,000 − Stock options/SARs exercised 77,002 195,242 278,916 Restricted stock grants 335,103 270,062 401,122 Restricted stock units vested 252,507 244,413 119,480 Treasury shares 23,671 15,566 29,278 Ending balance 169,316,460 168,628,177 163,342,894

Derivative Activities (Tables)

Derivative Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Volumes Hedged and Average Hedge Prices	The following table sets forth the derivative volumes by year as of December 31, 2015: Period Contract Type Volume Hedged Weighted Average Hedge Price Natural Gas 2016 Swaps 745,874 Mmbtu/day $3.24 2017 Swaps 20,000 Mmbtu/day $3.49 Crude Oil 2016 Swaps 4,247 bbls/day $65.27 2017 Swaps 500 bbls/day $55.00 NGLs (C3 - Propane) 2016 Swaps 5,500 bbls/day $0.60/gallon NGLs (NC4 – Normal Butane) 2016 Swaps 2,500 bbls/day $0.72/gallon NGLs (C5 - Natural Gasoline) 2016 Swaps 2,749 bbls/day $1.20/gallon
Combined Fair Value of Derivatives, by Consolidated Balance Sheets	The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2015 and 2014 is summarized below (in thousands). As of December 31, 2015, we are conducting derivative activities with seventeen counterparties, of which all but four are secured lenders in our bank credit facility. We believe all of these counterparties 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, 2015 Gross Amounts of Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 219,357 $ (10,245 ) $ 209,112 –natural gas basis swaps 8,251 (2,765 ) 5,486 Crude oil –swaps 38,699 ¾ 38,699 NGLs –C3 swaps 15,884 ¾ 15,884 –C3 basis 2,497 (2,497 ) ¾ –C4 swaps 6,968 ¾ 6,968 –C5 swaps 12,694 (81 ) 12,613 $ 304,350 $ (15,588 ) $ 288,762 December 31, 2015 Gross Amounts of Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –swaps $ (10,245 ) $ 10,245 $ ¾ –natural gas basis swaps (2,786 ) 2,765 (21 ) NGLs –C3 basis (3,633 ) 2,497 (1,136 ) –C5 swaps (81 ) 81 ¾ $ (16,745 ) $ 15,588 $ (1,157 ) December 31, 2014 Gross Amounts of Gross Amounts Net Amounts of Derivative assets: Natural gas –swaps $ 198,740 $ ¾ $ 198,740 –collars 57,460 ¾ 57,460 –basis swaps 2,442 (755 ) 1,687 Crude oil –swaps 128,578 ¾ 128,578 NGLs –C3 swaps 14,727 ¾ 14,727 –C5 swaps 2,171 ¾ 2,171 $ 404,118 $ (755 ) $ 403,363 December 31, 2014 Gross Amounts of Gross Amounts Net Amounts of Derivative (liabilities): Natural gas –basis swaps $ (755 ) $ 755 $ − $ (755 ) $ 755 $ −
Effects of Non-Hedge Derivatives on Consolidated Statements of Operations	The effects of our non-hedge derivatives (or those derivatives that do not qualify or are not designated for hedge accounting) on our consolidated statements of operations for the last three years are summarized below (in thousands). Derivative fair value for the year ended December 31, 2014 includes no ineffective gains or losses compared to ineffective loss of $2.9 million in the year ended December 31, 2013. Year Ended December 31, Derivative Fair Value Income (Loss) 2015 2014 2013 Swaps $ 398,020 $ 367,484 $ (50,526 ) Re-purchased swaps 851 ¾ 1,323 Collars 16,539 42,836 (16,062 ) Basis swaps 954 (26,800 ) 3,440 Total $ 416,364 $ 383,520 $ (61,825 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value	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, 2015 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 62,376 $ ¾ $ ¾ $ 62,376 Derivatives –swaps ¾ 283,276 ¾ 283,276 –basis swaps ¾ 4,329 ¾ 4,329 Fair Value Measurements at December 31, 2014 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 68,454 $ — $ — $ 68,454 Derivatives –swaps — 344,216 — 344,216 –collars — 57,460 — 57,460 –basis swaps — 1,687 — 1,687
Value of Assets Measured at Fair Value on Non Recurring Basis	The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands): Year Ended December 31, 2015 2014 2013 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ 152,230 $ 590,174 $ 15,605 $ 28,024 $ 500 $ 7,012 Surface property ¾ ¾ ¾ ¾ 5,550 741
Carrying Amounts and Fair Values of Financial Instruments	The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2015 and 2014 (in thousands): December 31, 2015 December 31, 2014 Carrying Fair Carrying Fair Value Assets: Commodity swaps, collars and basis swaps $ 288,762 $ 288,762 $ 403,363 $ 403,363 Marketable securities (a) 62,376 62,376 68,454 68,454 Liabilities: Commodity swaps, collars and basis swaps (1,157 ) (1,157 ) ¾ ¾ Bank credit facility (b) (95,000 ) (95,000 ) (723,000 ) (723,000 ) Deferred compensation plan (c) (122,918 ) (122,918 ) (203,433 ) (203,433 ) 4.875% senior notes due 2025 (b) (750,000 ) (572,813 ) ¾ ¾ 6.75% senior subordinated notes due 2020 (b) ¾ ¾ (500,000 ) (523,125 ) 5.75% senior subordinated notes due 2021 (b) (500,000 ) (396,250 ) (500,000 ) (520,000 ) 5.00% senior subordinated notes due 2022 (b) (600,000 ) (447,000 ) (600,000 ) (601,500 ) 5.00% senior subordinated notes due 2023 (b) (750,000 ) (551,250 ) (750,000 ) (754,688 ) (a) (b) (c) The fair value of our deferred compensation plan is updated based on closing prices on the balance sheet date.

Stock-based Compensation Plans

Stock-based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Allocation of Stock-Based Compensation by Functional Category	The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2015 (in thousands): 2015 2014 2013 Direct operating expense $ 2,780 $ 4,208 $ 2,755 Brokered natural gas and marketing expense 2,132 3,523 1,852 Exploration expense 2,985 4,569 4,025 General and administrative expense 49,687 55,382 55,737 Termination costs 217 2,999 ¾ Total $ 57,801 $ 70,681 $ 64,369
Summary of Performance Share Unit Award Activities	The following is a summary of our non-vested PSU award activities: (a) Weighted Outstanding at December 31, 2013 — $ — Granted 227,929 86.14 Vested (b) (92,077 ) 86.23 Forfeited (1,511 ) 82.60 Outstanding at December 31, 2014 134,341 86.11 Granted 276,204 56.78 Vested ( c ) (143,094 ) 68.73 Forfeited (5,327 ) 82.60 Outstanding at December 31, 2015 262,124 $ 64.77 (a) These (b) (c)
Schedule of Share Based Payment Award Performance Stock Awards Valuation Assumptions	The following assumptions were used to estimate the fair value of PSUs granted during the year ended December 31, 2015 and 2014: Year Ended December 31, 2015 2014 Risk-free interest rate 1.02 % 0.77 % Expected annual volatility 33 % 33 % Grant date fair value per unit $ 56.78 $ 86.14
Restricted Stock and Restricted Stock Units Outstanding	A summary of the status of our non-vested restricted stock outstanding at December 31, 2015 is summarized below: Equity Awards Liability Awards Shares Weighted Shares Weighted Outstanding at December 31, 2012 349,156 $ 59.08 423,478 $ 58.91 Granted 402,053 71.26 424,809 75.53 Vested (315,535 ) 62.43 (437,570 ) 64.36 Forfeited (50,611 ) 65.29 (21,704 ) 57.31 Outstanding at December 31, 2013 385,063 68.24 389,013 71.02 Granted 356,194 84.87 272,052 87.34 Vested (354,237 ) 72.85 (356,413 ) 75.52 Forfeited (26,605 ) 75.66 (148 ) 77.35 Outstanding at December 31, 2014 360,415 79.60 304,504 80.33 Granted 587,711 52.29 343,397 55.92 Vested (480,253 ) 65.21 (330,870 ) 68.71 Forfeited (31,109 ) 64.73 (8,294 ) 74.22 Outstanding at December 31, 2015 436,764 $ 59.74 308,737 $ 65.80
Stock Option and SARs Activities	Information with respect to our SARs activities is summarized below. During 2014, we granted SARs to our former executive chairman in conjunction with his retirement from Range as an employee. Shares Weighted Outstanding at December 31, 2012 3,433,362 $ 52.52 Granted 470,617 75.82 Exercised (1,269,323 ) 53.24 Expired/forfeited (52,582 ) 53.56 Outstanding at December 31, 2013 2,582,074 56.36 Granted 1,104 81.74 Exercised (616,563 ) 45.45 Expired/forfeited (66 ) 46.44 Outstanding at December 31, 2014 1,966,549 59.80 Exercised (427,598 ) 45.67 Expired/forfeited (27,974 ) 63.10 Outstanding at December 31, 2015 1,510,977 $ 63.73
Summary of SARs Outstanding and Exercisable	The following table shows information with respect to SARs outstanding and exercisable at December 31, 2015: Outstanding Exercisable Range of Exercise Prices Shares Weighted Weighted Average Exercise Price Shares Weighted Average Exercise Price $ 40.00–$ 49.99 112,769 0.13 $ 49.18 112,769 $ 49.18 50.00–59.99 355,052 0.38 52.35 355,052 52.35 60.00–69.99 602,926 1.34 64.19 602,926 64.19 70.00–79.99 438,330 2.28 75.99 301,641 76.08 80.00–81.15 1,900 2.69 81.15 1,900 81.15 Total 1,510,977 1.30 $ 63.73 1,374,288 $ 62.53
Weighted Average Grant Date Fair Value of SARs	The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below: 2014 2013 Weighted average exercise price per share $ 81.74 $ 75.82 Expected annual dividend yield 0.20 % 0.21 % Expected life in years 4.3 3.7 Expected volatility 33 % 35 % Risk-free interest rate 1.4 % 0.6 % Weighted average grant date fair value per share $ 23.17 $ 20.20

Supplemental Cash Flow Inform39

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Year Ended December 31, 2015 2014 2013 (in thousands) Net cash provided from operating activities included: Income taxes paid to (refunded from) taxing authorities $ 100 $ (156 ) $ (347 ) Interest paid 168,826 165,530 159,137 Non-cash investing and financing activities included: Asset retirement costs capitalized, net $ 22,184 $ 56,822 $ 76,373 (Decrease) increase in accrued capital expenditures (225,455 ) 150,604 27,079

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Rental Commitments	We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $15.9 million in 2015 compared to $13.3 million in 2014 and $13.1 million in 2013. 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 2016 $ 11,819 2017 10,014 2018 8,902 2019 7,264 2020 7,238 Thereafter 29,258 $ 74,495
Schedule of Future Minimum Transportation and Gathering Fees	We have entered into 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, 2015, future minimum transportation and gathering fees under our commitments are as follows (in thousands): Transportation (a) 2016 $ 407,046 2017 401,517 2018 366,914 2019 366,562 2020 359,595 Thereafter 1,748,559 $ 3,650,193
Future Delivery Commitments	We have various volume delivery commitments that are primarily related to our Marcellus Shale and Oklahoma and Texas areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2015, our delivery commitments through 2028 were as follows: Year Ending December 31, Natural Gas Ethane and Propane (bbls per day) 2016 405,126 40,000 2017 241,301 40,000 2018 — 40,000 2019 — 20,000 2020 — 20,000 2021 — 20,000 2022 ¾ — 15,000

Office Closing and Exit Costs (

Office Closing and Exit Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Restructuring And Related Activities [Abstract]
Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet	The following table details the accrued liability as of December 31, 2015 and December 31, 2014 (in thousands): 2015 2014 Beginning balance $ 5,372 $ — Accrued severance costs 11,706 5,372 Accrued building rent 3,147 — Payments (8,595 ) — Ending balance $ 11,630 $ 5,372
Summary of Termination Costs	The following summarizes our termination costs for the year ended December 31, 2015 and December 31, 2014 (in thousands): 2015 2014 Severance costs $ 11,706 $ 5,372 Building lease 3,147 — Stock-based compensation 217 2,999 Total termination costs $ 15,070 $ 8,371

Selected Quarterly Financial 42

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data	The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Fourth quarter 2015 includes a loss of $407.7 million from the sale of our Virginia and West Virginia oil and gas properties and impairment expense of $87.9 million related to oil and gas properties in the Texas Panhandle and South Texas. Third quarter 2015 includes impairment expense of $502.2 million related to our Northern Oklahoma and legacy shallow Northwest Pennsylvania assets. Second quarter 2014 includes a gain of $280.1 million from the Conger Exchange (in thousands, except per share data): 2015 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 325,483 $ 258,053 $ 252,065 $ 254,043 $ 1,089,644 Derivative fair value income (loss) 122,839 (34,791 ) 202,004 126,312 416,364 Brokered natural gas, marketing and other 14,485 21,339 25,864 30,372 92,060 Total revenue and other income 462,807 244,601 479,933 410,727 1,598,068 Costs and expenses: Direct operating 37,137 34,780 35,058 29,388 136,363 Transportation, gathering and compression 89,426 95,198 99,634 112,481 396,739 Production and ad valorem taxes 9,928 9,242 7,336 7,354 33,860 Brokered natural gas and marketing 21,562 27,031 32,331 34,942 115,866 Exploration 7,886 5,025 4,235 4,260 21,406 Abandonment and impairment of unproved properties 11,491 12,330 12,366 11,432 47,619 General and administrative 48,329 55,964 46,178 43,544 194,015 Termination costs 5,950 417 (77 ) 8,780 15,070 Deferred compensation plan (5,624 ) (7,282 ) (43,705 ) (21,016 ) (77,627 ) Interest 39,207 43,479 42,904 40,849 166,439 Loss on early extinguishment of debt — — 22,495 — 22,495 Depletion, depreciation and amortization 147,290 151,895 153,993 127,977 581,155 Impairment of proved properties and other — — 502,233 87,941 590,174 Loss (gain) on sale of assets 175 (2,909 ) 681 408,909 406,856 Total costs and expenses 412,757 425,170 915,662 896,841 2,650,430 Income (loss) before income taxes 50,050 (180,569 ) (435,729 ) (486,114 ) (1,052,362 ) Income tax expense (benefit): Current — — — 29 29 Deferred 22,366 (61,975 ) (134,781 ) (164,316 ) (338,706 ) 22,366 (61,975 ) (134,781 ) (164,287 ) (338,677 ) Net income (loss) $ 27,684 $ (118,594 ) $ (300,948 ) $ (321,827 ) $ (713,685 ) Net income (loss) per common share: Basic $ 0.16 $ (0.71 ) $ (1.81 ) $ (1.93 ) $ (4.29 ) Diluted $ 0.16 $ (0.71 ) $ (1.81 ) $ (1.93 ) $ (4.29 ) 2014 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 572,017 $ 477,517 $ 446,067 $ 416,388 $ 1,911,989 Derivative fair value (loss) income (146,850 ) (24,109 ) 142,057 412,422 383,520 Brokered natural gas, marketing and other 32,528 30,052 28,324 39,644 130,548 Total revenue and other income 457,695 483,460 616,448 868,454 2,426,057 Costs and expenses: Direct operating 39,795 34,935 37,792 37,961 150,483 Transportation, gathering and compression 74,161 76,809 84,777 89,542 325,289 Production and ad valorem taxes 11,678 10,844 10,110 11,923 44,555 Brokered natural gas and marketing 34,129 34,775 28,706 32,370 129,980 Exploration 14,846 13,621 11,443 23,638 63,548 Abandonment and impairment of unproved properties 9,995 9,332 13,444 14,308 47,079 General and administrative 49,212 56,888 54,963 52,363 213,426 Termination costs — — — 8,371 8,371 Deferred compensation plan (2,035 ) 10,519 (46,198 ) (36,836 ) (74,550 ) Interest 45,401 45,488 39,188 38,900 168,977 Loss on early extinguishment of debt — 24,596 — — 24,596 Depletion, depreciation and amortization 128,682 133,361 142,450 146,539 551,032 Impairment of proved properties and other — 24,991 — 3,033 28,024 Loss (gain) on sale of assets 353 (282,064 ) (167 ) (3,760 ) (285,638 ) Total costs and expenses 406,217 194,095 376,508 418,352 1,395,172 Income before income taxes 51,478 289,365 239,940 450,102 1,030,885 Income tax expense (benefit): Current 6 (1 ) — (4 ) 1 Deferred 18,951 117,977 93,522 166,052 396,502 18,957 117,976 93,522 166,048 396,503 Net income $ 32,521 $ 171,389 $ 146,418 $ 284,054 $ 634,382 Net income per common share: Basic $ 0.20 $ 1.04 $ 0.87 $ 1.68 $ 3.81 Diluted $ 0.20 $ 1.04 $ 0.86 $ 1.68 $ 3.79

Supplemental Information on N43

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization	Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2015 2014 2013 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 8,047,181 $ 9,624,725 $ 8,225,859 Unproved properties 949,155 943,246 807,022 Total 8,996,336 10,567,971 9,032,881 Accumulated depreciation, depletion and amortization (2,635,031 ) (2,590,398 ) (2,274,444 ) Net capitalized costs $ 6,361,305 $ 7,977,573 $ 6,758,437 (a)
Costs Incurred for Property Acquisition, Exploration and Development	Costs Incurred for Property Acquisition, Exploration (a) December 31, 2015 2014 2013 (in thousands) Acquisitions (b) $ ¾ $ 404,252 $ ¾ Acreage purchases 73,025 226,475 137,538 Development 708,268 1,119,896 938,668 Exploration: Drilling 87,505 180,925 189,742 Expense 18,421 58,979 60,384 Stock-based compensation expense 2,985 4,569 4,025 Gas gathering facilities: Development 13,337 13,137 47,086 Subtotal 903,541 2,008,233 1,377,443 Asset retirement obligations 22,184 56,822 76,373 Total costs incurred $ 925,725 $ 2,065,055 $ 1,453,816 (a) (b)
Proved Developed and Undeveloped Reserves	Natural Gas NGLs Crude Oil and Condensate Natural Gas (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: Balance, December 31, 2012 4,792,676 240,399 45,082 6,505,570 Revisions 384,825 7,743 2,935 448,898 Extensions, discoveries and additions 853,746 135,810 10,723 1,732,944 Purchases ¾ ¾ ¾ ¾ Property sales (101,074 ) (286 ) (6,553 ) (142,116 ) Production (264,528 ) (9,254 ) (3,827 ) (343,022 ) Balance, December 31, 2013 5,665,645 374,412 48,360 8,202,274 Revisions (30,566 ) 19,716 515 90,822 Extensions, discoveries and additions 1,393,108 154,664 12,936 2,398,709 Purchases 262,813 ¾ ¾ 262,813 Property sales (81,238 ) (14,064 ) (9,083 ) (220,122 ) Production (286,926 ) (18,821 ) (4,070 ) (424,267 ) Balance, December 31, 2014 6,922,836 515,907 48,658 10,310,229 Revisions (340,286 ) 17,717 3,804 (211,163 ) Extensions, discoveries and additions 1,017,956 36,308 4,924 1,265,348 Purchases ¾ ¾ ¾ ¾ Property sales (960,122 ) (441 ) (109 ) (963,423 ) Production (362,687 ) (20,356 ) (4,084 ) (509,328 ) Balance, December 31, 2015 6,277,697 549,135 53,193 9,891,663 Proved developed reserves: December 31, 2013 2,797,483 206,477 26,054 4,192,666 December 31, 2014 3,583,051 270,271 24,180 5,349,761 December 31, 2015 3,376,165 309,306 31,679 5,422,075 Proved undeveloped reserves: December 31, 2013 2,868,162 167,935 22,306 4,009,608 December 31, 2014 3,339,785 245,636 24,478 4,960,468 December 31, 2015 2,901,533 239,828 21,514 4,469,588 (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 indicative of the relationship of oil and natural gas prices.
Changes in Proved Undeveloped Reserves	The following details the changes in proved undeveloped reserves for 2015 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2014 4,960,468 Undeveloped reserves transferred to developed (762,936 ) Revisions (a) (441,874 ) Purchases/(sales) (201,809 ) Extension and discoveries 915,739 Ending proved undeveloped reserves at December 31, 2015 4,469,588 (a)
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives 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, 2015 2014 (in thousands) Future cash inflows $ 21,290,873 $ 46,507,646 Future costs: Production (10,411,360 ) (15,239,210 ) Development (a) (2,213,582 ) (4,275,693 ) Future net cash flows before income taxes 8,665,931 26,992,743 Future income tax expense (2,007,794 ) (8,900,383 ) Total future net cash flows before 10% discount 6,658,137 18,092,360 10% annual discount (3,932,274 ) (10,499,333 ) Standardized measure of discounted future net cash flows $ 2,725,863 $ 7,593,027 (a)
Changes in Discounted Future Net Cash Flows	The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2015 2014 2013 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ (7,231,629 ) $ 5,069 $ 2,172,704 Revisions in quantities (868,886 ) 102,760 513,168 Changes in future development and abandonment costs 359,540 (407,688 ) (275,468 ) Net change in income taxes 2,173,904 (441,935 ) (1,299,227 ) Accretion of discount 1,007,027 789,754 395,989 Purchases of reserves in place ¾ 297,358 ¾ Additions to proved reserves from extensions, discoveries and improved recovery 486,478 2,713,999 1,981,054 Natural gas, NGLs and oil sales, net of production costs (522,682 ) (1,391,663 ) (1,286,103 ) Development costs incurred during the period 1,033,539 755,384 462,862 Sales of reserves in place (1,050,237 ) (249,055 ) (162,463 ) Timing and other (254,218 ) (443,187 ) 135,910 Net change for the year (4,867,164 ) 1,730,796 2,638,426 Beginning of year 7,593,027 5,862,231 3,223,805 End of year $ 2,725,863 $ 7,593,027 $ 5,862,231

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Equity method investments				$ 0
Net brokered margin gain (loss)	$ (2,700,000)	$ 9,400,000	$ (5,700,000)
Allowance for doubtful accounts on accounts receivable	4,994,000	2,719,000
Bad debt expense	2,300,000	250,000	$ 250,000
Inventory, other	33,217,000	17,854,000
Materials and supplies inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory, other	20,800,000	11,800,000
Commodity inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory, other	$ 4,800,000	$ 2,000,000

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Additional Information 1 (Detail) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Net book value of unproved properties	[1]	$ 949,155				$ 943,246				$ 949,155	$ 943,246	$ 807,022
Abandonment and impairment of unproved properties		11,432	$ 12,366	$ 12,330	$ 11,491	14,308	$ 13,444	$ 9,332	$ 9,995	47,619	47,079	51,918
Depreciation expense										11,900	12,900	$ 13,200
Marketable securities held in deferred compensation plans		62,400				68,500				62,400	68,500
Surface acreage		$ 10,600				$ 10,300				$ 10,600	$ 10,300
Minimum | Other property and equipment
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets										3 years
Maximum | Other property and equipment
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets										10 years
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Additional Information 2 (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)CustomerCounterparty	Dec. 31, 2014USD ($)Customer	Dec. 31, 2013Customer
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 5	$ 2.7
Number of customers accounted more than 10% of total oil and gas revenues | Customer	1	4	4
Net derivative asset	$ 11.5
Number of counterparties | Counterparty	4
Total Number of Derivative Counterparties | Counterparty	17
Accounting Standards Update 2015-04 | Subordinated Debt
Summary Of Significant Accounting Policies [Line Items]
Prior period reclassification		$ 32.4
Accounting Standards Update 2015-04 | Bank Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Prior period reclassification		9.8
Accounting Standards Update 2015-11
Summary Of Significant Accounting Policies [Line Items]
Prior period reclassification		$ 115.6

Summary of Significant Accoun47

Summary of Significant Accounting Policies - Accumulated Other Comprehensive Income (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Summary Of Significant Accounting Policies Accumulated Other Comprehensive Income [Abstract]
Beginning Balance, Gross		$ 0	$ 10,222	$ 137,555
Contract settlements reclassified to income, Gross			(10,222)	(120,443)
Change in unrealized deferred hedging gains (losses), Gross				(6,890)
Ending Balance, Gross			0	10,222
Beginning Balance, Tax Effect		0	(3,986)	(53,646)
Contract settlements reclassified to income, Tax Effect			3,986	46,973
Change in unrealized deferred hedging (losses) gains, tax effect				2,687
Ending Balance, Tax Effect			0	(3,986)
Beginning Balance, Net of Tax		0	6,236	83,909
Contract settlements reclassified to income, Net of Tax			(6,236)	(73,470)
Change in unrealized deferred hedging (losses) gains, net of taxes	[1]	$ 0	0	(4,203)
Ending Balance, Net of Tax			$ 0	$ 6,236
[1]	Amounts are net of income tax benefit of $2,687 for the year ended December 31, 2013.

Acquisitions and Dispositions -

Acquisitions and Dispositions - Additional Information (Detail) - USD ($)	1 Months Ended			3 Months Ended								6 Months Ended		10 Months Ended	12 Months Ended
	Feb. 28, 2015	Apr. 30, 2014	Apr. 30, 2013	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Jun. 16, 2014	Nov. 01, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets				$ (408,909,000)	$ (681,000)	$ 2,909,000	$ (175,000)	$ 3,760,000	$ 167,000	$ 282,064,000	$ (353,000)				$ (406,856,000)	$ 285,638,000	$ 92,291,000
Conger Exchange Transaction
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets										$ 280,100,000
Cash proceeds from sale of assets		$ 145,000,000
Net operating income prior to disposition												$ 25,700,000	$ 21,900,000				48,700,000
Gain on sale of assets after selling expenses																272,700,000
Sale and exchange transaction, closing date															Jun. 16, 2014
Selling expenses for property sale																$ 5,000,000
Recognized revenue from sale of property interests acquire												$ 33,800,000
Nora Gathering, LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Percentage of ownership interest, acquired								50.00%				50.00%				50.00%
Percentage ownership interest								50.00%				50.00%				50.00%
Fair value of membership interest on acquisition date																$ 134,800,000
Nora Gathering, LLC | Conger Exchange Transaction
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain on fair value of membership interest																10,000,000
Virginia And West Virginia Property
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets				$ (407,700,000)											$ (407,700,000)
Cash proceeds from sale of assets															876,000,000
Net operating income prior to disposition														$ 52,300,000		98,300,000	46,100,000
West Texas Properties
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets	$ (101,000)
Proceeds from sale of oil and gas	$ 10,500,000
Miscellaneous Proved, Unproved Properties and Surface Acreage
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets															943,000	3,000,000	13,200,000
Proceeds from sale of oil and gas															$ 4,400,000	$ 35,500,000	$ 40,500,000
Delaware and Permian Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
(Loss) gain on the sale of assets			$ 83,300,000
Proceeds from sale of oil and gas			275,000,000
Selling expenses for property sale			$ 4,200,000

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Income tax (benefit) expense	$ (164,287,000)	$ (134,781,000)	$ (61,975,000)	$ 22,366,000	$ 166,048,000	$ 93,522,000	$ 117,976,000	$ 18,957,000	$ (338,677,000)	$ 396,503,000	$ 33,857,000
Deferred tax liabilities	777,947,000				1,113,081,000				777,947,000	1,113,081,000
Deductible limit	1,000,000								1,000,000
Net operating loss and credit carry forwards, state	32,700,000								32,700,000
Regular net operating loss carryforwards	620,600,000								620,600,000
Alternative minimum tax carryforwards	539,300,000								539,300,000
Deferred tax asset related to regular NOL	123,500,000								123,500,000
Accrued interest or penalties related to tax amounts	0								$ 0
Minimum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2018
Maximum
Income Taxes [Line Items]
Period during which net operating loss carryforwards and alternative minimum tax expire									Dec. 31, 2035
Alternative Minimum Tax
Income Taxes [Line Items]
AMT credit carryforwards that are not subject to limitation or expiration	665,000								$ 665,000
Louisiana, Mississippi, Oklahoma and West Virginia
Income Taxes [Line Items]
Net operating loss and credit carry forwards, state	15,600,000								15,600,000
Pennsylvania
Income Taxes [Line Items]
Valuation allowance to net operating loss carryforward	16,000,000								16,000,000
Texas Margin
Income Taxes [Line Items]
Valuation allowance tax credit carryforward	1,000,000								1,000,000
Federal
Income Taxes [Line Items]
Valuation allowances	42,500,000				$ 0				42,500,000	$ 0
Deferred compensation plan
Income Taxes [Line Items]
Valuation allowances	$ 3,100,000								$ 3,100,000

Income Taxes - Reconciliation B

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Effective Income Tax Rate Continuing Operations Tax Rate Reconciliation [Abstract]
Federal statutory tax rate	35.00%	35.00%	35.00%
State	4.30%	3.10%	(2.30%)
State apportionment rate change	(0.20%)	(0.20%)	(14.90%)
Non-deductible executive compensation	(0.10%)	0.20%	0.70%
Valuation allowances	(6.80%)	0.20%	3.50%
Other	0.00%	0.20%	0.60%
Consolidated effective tax rate	32.20%	38.50%	22.60%

Income Taxes - Income Tax (Bene

Income Taxes - Income Tax (Benefit) Expense Attributable to Income Before Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Components Of Income Tax Expense Benefit Continuing Operations [Abstract]
U.S. federal, Current									$ 0
U.S. state and local, Current									29	$ 1	$ (143)
Total, Current	$ 29				$ (4)		$ (1)	$ 6	29	1	(143)
U.S. federal, Deferred									(328,257)	361,152	58,527
U.S. state and local, Deferred									(10,449)	35,350	(24,527)
Total, Deferred	(164,316)	$ (134,781)	$ (61,975)	$ 22,366	166,052	$ 93,522	117,977	18,951	(338,706)	396,502	34,000
U.S. federal, Total									(328,257)	361,152	58,527
U.S. state and local, Total									(10,420)	35,351	(24,670)
Total income tax expense	$ (164,287)	$ (134,781)	$ (61,975)	$ 22,366	$ 166,048	$ 93,522	$ 117,976	$ 18,957	$ (338,677)	$ 396,503	$ 33,857

Income Taxes - Significant Comp

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Net operating loss carryforward	$ 173,503	$ 176,812
Deferred compensation	45,413	73,942
Equity compensation	25,940	25,833
AMT credits and other credits	4,437	4,447
Asset retirement obligation	101,142	109,808
Cumulative mark-to-market loss	0	649
Other	10,163	10,908
Valuation allowances:
Total deferred tax assets	272,975	385,800
Deferred tax liabilities:
Depreciation, depletion and investments	(940,482)	(1,342,038)
Cumulative mark-to-market gain	(109,845)	(154,183)
Other	(595)	(2,660)
Total deferred tax liabilities	(1,050,922)	(1,498,881)
Net deferred tax liability	(777,947)	(1,113,081)
Federal
Valuation allowances:
Valuation allowances	(42,500)	0
State, net of federal benefit
Valuation allowances:
Valuation allowances	(41,516)	(8,800)
Deferred compensation plans and other
Valuation allowances:
Valuation allowances	$ (3,607)	$ (7,799)

Net (Loss) Income Per Common 53

Net (Loss) Income Per Common Share - Computations of Basic and Diluted (Loss) Income Per Common Share (Detail) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share Reconciliation [Abstract]
Net (loss) income, as reported		$ (321,827)	$ (300,948)	$ (118,594)	$ 27,684	$ 284,054	$ 146,418	$ 171,389	$ 32,521	$ (713,685)	$ 634,382	$ 115,722
Participating basic earnings	[1]									(450)	(10,725)	(1,975)
Basic net (loss) income attributed to common stockholders										(714,135)	623,657	113,747
Reallocation of participating earnings	[1]									0	48	9
Diluted net (loss) income attributed to common stockholders										$ (714,135)	$ 623,705	$ 113,756
Net (loss) income per common share:
Basic		$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ 1.68	$ 0.87	$ 1.04	$ 0.20	$ (4.29)	$ 3.81	$ 0.71
Diluted		$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ 1.68	$ 0.86	$ 1.04	$ 0.20	$ (4.29)	$ 3.79	$ 0.70
[1]	Restricted stock Liability 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.

Net (Loss) Income Per Common 54

Net (Loss) Income Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Denominator:
Weighted average common shares outstanding – basic	166,389	163,625	160,438
Effect of dilutive securities:
Director and employee SARs and restricted stock Equity Awards	0	778	969
Weighted average common shares outstanding – diluted	166,389	164,403	161,407

Net (Loss) Income Per Common 55

Net (Loss) Income Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Appreciation Rights (SARs)
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation		1,900	226,000
Restricted Stock Liability Awards
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Stock excluded from earning per share calculation	2,800,000	2,800,000	2,800,000

Suspended Exploratory Well Co56

Suspended Exploratory Well Costs - Suspended Exploratory Well Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Project	Dec. 31, 2014USD ($)Project	Dec. 31, 2013USD ($)Project
Extractive Industries [Abstract]
Balance at beginning of period	$ 2,996	$ 6,964	$ 57,360
Additions to capitalized exploratory well costs pending the determination of proved reserves	1,165	18,747	39,832
Reclassifications to wells, facilities and equipment based on determination of proved reserves	0	(15,735)	(84,840)
Capitalized exploratory well costs charged to expense	0	(6,980)	(5,388)
Balance at end of period	4,161	2,996	6,964
Less exploratory well costs that have been capitalized for a period of one year or less	(1,165)	(2,996)	0
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 2,996	$ 0	$ 6,964
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | Project	1	0	1

Suspended Exploratory Well Co57

Suspended Exploratory Well Costs - Additional Information (Detail) $ in Thousands	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Extractive Industries [Abstract]
Capitalized exploratory well costs that have been capitalized for a period greater than one year | $	$ 2,996	$ 0	$ 6,964
Number of well in completion phase | Well	1

Suspended Exploratory Well Co58

Suspended Exploratory Well Costs - Aging of Capitalized Exploratory Well Costs Suspended more than One Year (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been suspended for more than one year	$ 2,996	$ 0	$ 6,964
2,014
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been suspended for more than one year	$ 2,996

Indebtedness - Additional Infor

Indebtedness - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0	$ 0	$ 0

Indebtedness - Debt Outstanding

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Bank debt	$ 86,427	$ 713,221
Senior notes	738,101	0
Senior subordinated notes	1,826,775	2,317,603
Total debt	2,651,303	3,030,824
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Senior notes	738,101	0
Notes Payable to Banks | 1.8% Bank Debt
Debt Instrument [Line Items]
Bank debt	86,427	713,221
Senior Subordinated Notes | 6.75% Senior Subordinated Notes Due 2020
Debt Instrument [Line Items]
Senior subordinated notes	0	493,843
Senior Subordinated Notes | 5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Senior subordinated notes	494,095	493,197
Senior Subordinated Notes | 5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Senior subordinated notes	592,223	591,180
Senior Subordinated Notes | 5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Senior subordinated notes	$ 740,457	$ 739,383

Indebtedness - Debt Outstandi61

Indebtedness - Debt Outstanding (Parenthetical) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Jul. 31, 2015	May. 31, 2015	Dec. 31, 2014
Notes Payable to Banks | 1.8% Bank Debt
Debt Instrument [Line Items]
Bank debt percentage	1.80%
Unamortized debt issuance costs, net	$ 8,573			$ 9,779
Senior Notes | 4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Interest rate on notes	4.875%		4.875%	4.875%
Unamortized debt issuance costs, net	$ 11,899			$ 0
Senior Subordinated Notes | 6.75% Senior Subordinated Notes Due 2020
Debt Instrument [Line Items]
Interest rate on notes	6.75%	6.75%	6.75%	6.75%
Unamortized debt issuance costs, net	$ 6,157			$ 6,157
Senior Subordinated Notes | 5.75% Senior Subordinated Notes Due 2021
Debt Instrument [Line Items]
Interest rate on notes	5.75%			5.75%
Unamortized debt issuance costs, net	$ 5,905			$ 6,803
Senior Subordinated Notes | 5.00% Senior Subordinated Notes Due 2022
Debt Instrument [Line Items]
Interest rate on notes	5.00%			5.00%
Unamortized debt issuance costs, net	$ 7,777			$ 8,820
Senior Subordinated Notes | 5.00% Senior Subordinated Notes Due 2023
Debt Instrument [Line Items]
Interest rate on notes	5.00%			5.00%
Unamortized debt issuance costs, net	$ 9,543			$ 10,617

Indebtedness - Bank Debt - Addi

Indebtedness - Bank Debt - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2015USD ($)CommercialBank	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Bank Credit facility, maximum amount	$ 4,000,000,000
Bank Credit facility, borrowing base	3,000,000,000
Bank commitments	$ 2,000,000,000
Percentage holding of commercial banks, Maximum	5.80%
Number of commercial banks included in current bank group | CommercialBank	29
Maturity date of loan	Oct. 16, 2019
Bank debt	$ 95,000,000
Undrawn letters of credit	137,900,000
Borrowing capacity available under the commitment amount	$ 1,800,000,000
Weighted average interest rate on the bank credit facility	1.70%	2.00%	2.00%
Annual rate of commitment fee paid on the undrawn balance	0.30%
Alternate Base Rate
Debt Instrument [Line Items]
Minimum range of base rate	0.25%
Maximum range of base rate	1.25%
Interest rate margin	0.25%
Alternate Base Rate | Credit Facility
Debt Instrument [Line Items]
Minimum range of base rate	0.125%
Maximum range of base rate	0.75%
LIBOR Rate
Debt Instrument [Line Items]
Minimum range of base rate	1.25%
Maximum range of base rate	2.25%
Interest rate margin	1.25%
LIBOR Rate | Credit Facility
Debt Instrument [Line Items]
Minimum range of base rate	1.125%
Maximum range of base rate	1.75%
Minimum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%
Minimum | Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.15%
Maximum
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.375%
Maximum | Credit Facility
Debt Instrument [Line Items]
Annual rate of commitment fee paid on the undrawn balance	0.30%

Indebtedness - Senior Notes - A

Indebtedness - Senior Notes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended
	May. 31, 2015	Dec. 31, 2015	Jul. 31, 2015	Dec. 31, 2014
4.875% Senior Notes Due 2025
Debt Instrument [Line Items]
Aggregate principal amount	$ 750
4.875% Senior Notes Due 2025 | Senior Notes
Debt Instrument [Line Items]
Interest rate on notes	4.875%	4.875%		4.875%
Net proceeds after underwriting discounts and commissions	$ 737.4
Underwriting discounts and commissions	$ 12.6
Debt instrument redemption, percentage of principal amount	100.00%
6.75% Senior Subordinated Notes Due 2020 | Senior Subordinated Notes
Debt Instrument [Line Items]
Interest rate on notes	6.75%	6.75%	6.75%	6.75%

Indebtedness - Senior Subordina

Indebtedness - Senior Subordinated Notes and Early Extinguishment of Debt - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		12 Months Ended
	Jul. 31, 2015	Sep. 30, 2015	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	May. 31, 2015
Debt Instrument [Line Items]
Loss on early extinguishment of debt		$ 22,495	$ 24,596	$ 22,495	$ 24,596	$ 12,280
Subordinated Debt
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount				101.00%
Subordinated Debt | 8.0% Senior Subordinated notes due 2019
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount					104.00%
Announced call for redemption amount of debt					$ 300,000
Interest rate on notes					8.00%
Debt instrument, redemption description				In 2014, we announced a call for the redemption of $300.0 million of our outstanding 8.0% senior subordinated notes due 2019 at 104.0% of par plus accrued and unpaid interest which were redeemed on June 26, 2014.
Senior Subordinated Notes | 6.75% Senior Subordinated Notes Due 2020
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount	103.375%
Announced call for redemption amount of debt	$ 500,000
Interest rate on notes	6.75%			6.75%	6.75%		6.75%
Debt instrument, redemption description				In July 2015, we announced a call for the redemption of $500.0 million of our outstanding 6.75% senior subordinated notes due 2020 at a price of 103.375% of par plus accrued and unpaid interest, which were redeemed on August 3, 2015. In third quarter 2015, we recognized a loss on early extinguishment of debt of $22.5 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt
Senior Subordinated Notes | 7.25% Senior Subordinated notes due 2018
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount						103.625%
Announced call for redemption amount of debt						$ 250,000
Interest rate on notes						7.25%

Indebtedness - Guarantees and D

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility	12 Months Ended
	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Debt instrument, Covenant compliance	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 certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2015. 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, 2015, we were in compliance with these covenants. Our senior subordinated notes also include a limitation on the amount of credit facility debt we can incur. Certain thresholds, as set forth in the indenture debt incurrence test, may limit our ability to incur debt under our bank credit facility in excess of a $1.5 billion floor amount based on the levels of commodity prices for natural gas, NGLs and crude oil used in the annual calculation of discounted future net cash flows relating to proved oil and gas reserves. Based on the year-end 2015 discounted future net cash flows, our bank credit facility usage is limited to $1.5 billion until higher prices or proved reserve additions increase discounted future net cash flows.
Senior Subordinated Notes
Debt Instrument [Line Items]
Bank credit facility, debt incurrence limit	$ 1,500,000,000
Bank Credit facility, current usage limit	$ 1,500,000,000
Maximum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	250.00%
Present Value Of Proved Reserves To Total Debt.	150.00%
Minimum
Debt Instrument [Line Items]
Current ratio	100.00%

Indebtedness - Schedule for Lon

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Debt Disclosure [Abstract]
2,016	$ 0
2,017	0
2,018	0
2,019	95,000
2,020	0
Thereafter	2,600,000
Total debt	$ 2,695,000

Asset Retirement Obligations -

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Beginning of period	$ 287,463	$ 230,077
Liabilities incurred	4,595	8,602
Acquisitions	1,584	11,927
Liability released	0	(8,309)
Liabilities settled	(18,828)	(4,442)
Disposition of wells	(45,845)	(13,951)
Accretion expense	19,163	15,226
Change in estimate	16,005	48,333
End of period	264,137	287,463
Less current portion	(15,071)	(15,067)
Long-term asset retirement obligations	$ 249,066	$ 272,396

Capital Stock - Additional Info

Capital Stock - Additional Information (Detail) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class Of Stock Disclosures [Abstract]
Authorized capital stock	485,000,000				485,000,000								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
Common 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

Capital Stock (Detail)

Capital Stock (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class Of Stock [Line Items]
Beginning balance	168,628,177	163,342,894	162,514,098
Stock options/SARs exercised	77,002	195,242	278,916
Restricted stock grants	335,103	270,062	401,122
Restricted stock units vested	252,507	244,413	119,480
Treasury shares	23,671	15,566	29,278
Ending balance	169,316,460	168,628,177	163,342,894
Common Stock
Class Of Stock [Line Items]
Equity offering	665,000	5,270,000	799,000
Common Stock | Equity Offering
Class Of Stock [Line Items]
Equity offering	0	4,560,000	0

Derivative Activities - Additio

Derivative Activities - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MMBTU / dbblCounterpartyInstitution	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Derivative [Line Items]
Number of financial institutions with whom we conduct derivative activities | Institution	17
Number of secured lenders not in banking credit facility | Counterparty	4
Gain (Loss) Recognized in Income (Ineffective Portion)	$ 0	$ 0	$ (2,930)
Not Designated as Hedging Instrument
Derivative [Line Items]
Accumulated other comprehensive income, net gains	103,600
Accumulated other comprehensive income, net gains, after tax	63,200
Designated as Hedging Instrument
Derivative [Line Items]
Gains (Losses) in oil and gas sales related to settled hedging transactions		$ 10,200	$ 116,500
Derivatives Excluding Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	283,300
Natural Gas | Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 5,500
Volume Hedged | MMBTU / d	53,365,000
Propane | Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ (1,100)
Volume Hedged | bbl	4,679

Derivative Activities - Derivat

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail) - Swaps	Dec. 31, 2015MMBTU / dbbl / d$ / MMBTU$ / bbl$ / gal
Natural Gas | 2016
Derivative [Line Items]
Volume Hedged | MMBTU / d	745,874
Average hedge price | $ / MMBTU	3.24
Natural Gas | 2017
Derivative [Line Items]
Volume Hedged | MMBTU / d	20,000
Average hedge price | $ / MMBTU	3.49
Crude Oil | 2016
Derivative [Line Items]
Volume Hedged	4,247
Average hedge price | $ / bbl	65.27
Crude Oil | 2017
Derivative [Line Items]
Volume Hedged	500
Average hedge price | $ / bbl	55
Commodity Contract NGLs (C3 - Propane) | 2016
Derivative [Line Items]
Volume Hedged	5,500
Average hedge price | $ / gal	0.60
Commodity Contract NGLs (NC4 – Normal Butane) | 2016
Derivative [Line Items]
Volume Hedged	2,500
Average hedge price | $ / gal	0.72
Commodity Contract NGLs (C5 - Natural Gasoline) | 2016
Derivative [Line Items]
Volume Hedged	2,749
Average hedge price | $ / gal	1.20

Derivative Activities - Schedul

Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 304,350	$ 404,118
Gross Amounts Offset in the Balance Sheet	(15,588)	(755)
Net Amounts of Assets Presented in the Balance Sheet	288,762	403,363
Gross Amounts of Recognized (Liabilities)	(16,745)	(755)
Gross Amounts Offset in the Balance Sheet	15,588	755
Net Amounts of (Liabilities) Presented in the Balance Sheet	(1,157)	0
Natural Gas | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	219,357	198,740
Gross Amounts Offset in the Balance Sheet	(10,245)	0
Net Amounts of Assets Presented in the Balance Sheet	209,112	198,740
Gross Amounts of Recognized (Liabilities)	(10,245)
Gross Amounts Offset in the Balance Sheet	10,245
Net Amounts of (Liabilities) Presented in the Balance Sheet	0
Natural Gas | Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets		57,460
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		57,460
Natural Gas | Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	8,251	2,442
Gross Amounts Offset in the Balance Sheet	(2,765)	(755)
Net Amounts of Assets Presented in the Balance Sheet	5,486	1,687
Gross Amounts of Recognized (Liabilities)	(2,786)	(755)
Gross Amounts Offset in the Balance Sheet	2,765	755
Net Amounts of (Liabilities) Presented in the Balance Sheet	(21)	0
Crude Oil | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	38,699	128,578
Gross Amounts Offset in the Balance Sheet	0	0
Net Amounts of Assets Presented in the Balance Sheet	38,699	128,578
Commodity Contract NGLs (C3 - Propane) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	15,884	14,727
Gross Amounts Offset in the Balance Sheet	0	0
Net Amounts of Assets Presented in the Balance Sheet	15,884	14,727
Commodity Contract NGLs (C3 - Propane) | Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	2,497
Gross Amounts Offset in the Balance Sheet	(2,497)
Net Amounts of Assets Presented in the Balance Sheet	0
Gross Amounts of Recognized (Liabilities)	(3,633)
Gross Amounts Offset in the Balance Sheet	2,497
Net Amounts of (Liabilities) Presented in the Balance Sheet	(1,136)
Commodity Contract NGLs (C5 - Natural Gasoline) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		2,171
Gross Amounts Offset in the Balance Sheet		0
Net Amounts of Assets Presented in the Balance Sheet		$ 2,171
Gross Amounts of Recognized (Liabilities)	(81)
Gross Amounts Offset in the Balance Sheet	81
Net Amounts of (Liabilities) Presented in the Balance Sheet	0
Commodity Contract NGLs (C4 - Propane) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	6,968
Gross Amounts Offset in the Balance Sheet	0
Net Amounts of Assets Presented in the Balance Sheet	6,968
Commodity Contract NGLs (C5 - Natural Propane) | Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	12,694
Gross Amounts Offset in the Balance Sheet	(81)
Net Amounts of Assets Presented in the Balance Sheet	$ 12,613

Derivative Activities - Effects

Derivative Activities - Effects of Non-Hedge Derivatives on Consolidated Statement of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative Fair Value Income (Loss)	$ 126,312	$ 202,004	$ (34,791)	$ 122,839	$ 412,422	$ 142,057	$ (24,109)	$ (146,850)	$ 416,364	$ 383,520	$ (61,825)
Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									398,020	367,484	(50,526)
Re-purchased Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									851	0	1,323
Collars
Derivative [Line Items]
Derivative Fair Value Income (Loss)									16,539	42,836	(16,062)
Basis Swaps
Derivative [Line Items]
Derivative Fair Value Income (Loss)									$ 954	$ (26,800)	$ 3,440

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 62,376	$ 68,454
Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	283,276	344,216
Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	4,329	1,687
Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		57,460
Fair Value, Inputs, Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	62,376	68,454
Fair Value, Inputs, Level 1 | Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 1 | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		0
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	0	0
Fair Value, Inputs, Level 2 | Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	283,276	344,216
Fair Value, Inputs, Level 2 | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	4,329	1,687
Fair Value, Inputs, Level 2 | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		57,460
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	0	0
Fair Value, Inputs, Level 3 | Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	0	0
Fair Value, Inputs, Level 3 | Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	$ 0	0
Fair Value, Inputs, Level 3 | Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net		$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends					$ 908,000	$ 911,000	$ 1,200,000
Mark-to-market gain (loss)					5,900,000	2,400,000	3,900,000
Impairment of proved properties and other assets	$ 87,941,000	$ 502,233,000	$ 3,033,000	$ 24,991,000	590,174,000	28,024,000	7,753,000
Northwest Pennsylvania
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties					195,600,000
Northern Oklahoma
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties					306,600,000
Texas Panhandle
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties					86,900,000
Gulf Coast
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties					1,100,000		7,000,000
Mississippi
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties						5,500,000
West Texas
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties						18,500,000
North Texas
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties						4,000,000
Surface Property | Fair Value, Measurements, Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties and other assets					$ 0	$ 0	$ 741,000

Fair Value Measurements - Value

Fair Value Measurements - Value of Assets Measured at Fair Value on Non Recurring Basis (Detail) - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved properties and other assets	$ 87,941,000	$ 502,233,000	$ 3,033,000	$ 24,991,000	$ 590,174,000	$ 28,024,000	$ 7,753,000
Fair Value, Measurements, Nonrecurring | Natural Gas and Oil Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value					152,230,000	15,605,000	500,000
Impairment of proved properties and other assets					590,174,000	28,024,000	7,012,000
Fair Value, Measurements, Nonrecurring | Surface Property
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value					0	0	5,550,000
Impairment of proved properties and other assets					$ 0	$ 0	$ 741,000

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Carrying Value
Assets:
Commodity swaps, collars and basis swaps		$ 288,762	$ 403,363
Marketable securities	[1]	62,376	68,454
Liabilities:
Commodity swaps, collars and basis swaps		(1,157)	0
Bank credit facility	[2]	(95,000)	(723,000)
Deferred compensation plan	[3]	(122,918)	(203,433)
Carrying Value | 4.875% Senior Notes Due 2025
Liabilities:
Subordinated debt	[2]	(750,000)	0
Carrying Value | 6.75% Senior Subordinated Notes Due 2020
Liabilities:
Subordinated debt	[2]	0	(500,000)
Carrying Value | 5.75% Senior Subordinated Notes Due 2021
Liabilities:
Subordinated debt	[2]	(500,000)	(500,000)
Carrying Value | 5.00% Senior Subordinated Notes Due 2022
Liabilities:
Subordinated debt	[2]	(600,000)	(600,000)
Carrying Value | 5.00% Senior Subordinated Notes Due 2023
Liabilities:
Subordinated debt	[2]	(750,000)	(750,000)
Fair Value
Assets:
Commodity swaps, collars and basis swaps		288,762	403,363
Marketable securities	[1]	62,376	68,454
Liabilities:
Commodity swaps, collars and basis swaps		(1,157)	0
Bank credit facility	[2]	(95,000)	(723,000)
Deferred compensation plan	[3]	(122,918)	(203,433)
Fair Value | 4.875% Senior Notes Due 2025
Liabilities:
Subordinated debt	[2]	(572,813)	0
Fair Value | 6.75% Senior Subordinated Notes Due 2020
Liabilities:
Subordinated debt	[2]	0	(523,125)
Fair Value | 5.75% Senior Subordinated Notes Due 2021
Liabilities:
Subordinated debt	[2]	(396,250)	(520,000)
Fair Value | 5.00% Senior Subordinated Notes Due 2022
Liabilities:
Subordinated debt	[2]	(447,000)	(601,500)
Fair Value | 5.00% Senior Subordinated Notes Due 2023
Liabilities:
Subordinated debt	[2]	$ (551,250)	$ (754,688)
[1]	Marketable securities are held in our deferred compensation plans that are actively traded on major exchanges.
[2]	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes, which are Level 2 inputs.
[3]	The fair value of our deferred compensation plan is updated based on closing prices on the balance sheet date.

Fair Value Measurements - Car78

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Parenthetical) (Detail)	Dec. 31, 2015	Jul. 31, 2015	May. 31, 2015	Dec. 31, 2014
Senior Notes | 4.875% Senior Notes Due 2025
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	4.875%		4.875%	4.875%
Senior Subordinated Notes | 6.75% Senior Subordinated Notes Due 2020
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	6.75%	6.75%	6.75%	6.75%
Senior Subordinated Notes | 5.75% Senior Subordinated Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.75%			5.75%
Senior Subordinated Notes | 5.00% Senior Subordinated Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%			5.00%
Senior Subordinated Notes | 5.00% Senior Subordinated Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on notes	5.00%			5.00%

Stock-based Compensation Plan79

Stock-based Compensation Plans - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted		1,104	470,617
Vesting period	3 years
Stock Appreciation Rights (SARs) | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration term of stock units	5 years
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
2005 Equity Based Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares issued under the plans	5,600,000
1999 Stock Option Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted	0

Stock-based Compensation Plan80

Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense		$ 57,801	$ 70,681	$ 64,369
Direct Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense		2,780	4,208	2,755
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense		2,132	3,523	1,852
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	[1]	2,985	4,569	4,025
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense		49,687	55,382	55,737
Termination Costs
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense		$ 217	$ 2,999	$ 0
[1]	Includes cost incurred whether capitalized or expensed.

Stock-based Compensation Plan81

Stock-based Compensation Plans - Additional Information 1 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 57,801	$ 70,681	$ 64,369
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	8,700	7,900	$ 0
Unrecognized compensation related to Awards	$ 15,700
Weighted average period	1 year 10 months 24 days
Former Executive Chairman
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense		$ 6,700

Stock-based Compensation Plan82

Stock-based Compensation Plans - PSUA Activities (Detail) - Performance Shares - $ / shares		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014
Summary of Performance Share Unit Awards outstanding, Number of Units
Outstanding, Beginning Balance	[1]	134,341		0
Granted	[1]	276,204		227,929
Vested	[1]	(143,094)	[2]	(92,077)	[3]
Forfeited	[1]	(5,327)		(1,511)
Outstanding, Ending Balance	[1]	262,124		134,341
Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value
Outstanding, Beginning Balance, weighted average grant date fair value		$ 86.11		$ 0
Granted, weighted average grant date fair value		56.78		86.14
Vested, weighted average grant date fair value		68.73	[2]	86.23	[3]
Forfeited, weighted average grant date fair value		82.60		82.60
Outstanding, Ending Balance, weighted average grant date fair value		$ 64.77		$ 86.11
[1]	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 150% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date.
[2]	Includes PSU awards of 19,684 that were modified and fully vested effective with the closing of our Oklahoma City Office and the sale of our Virginia and West Virginia assets.
[3]	Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

Stock-based Compensation Plan83

Stock-based Compensation Plans - PSUA Activities (Parenthetical) (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Oklahoma, Virginia And West Virginia
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares vested in period on performance number of units	19,684
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares on performance units granted	0.00%	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares on performance units granted	150.00%	150.00%

Stock-based Compensation Plan84

Stock-based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	1.02%	0.77%
Expected annual volatility	33.00%	33.00%
Grant date fair value per unit	$ 56.78	$ 86.14

Stock-based Compensation Plan85

Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 57,801,000	$ 70,681,000	$ 64,369,000
Proceeds from the sales of common stock held by the deferred compensation plan	8,298,000	15,964,000	20,681,000
Total intrinsic value of stock options and SARs exercised	5,400,000	$ 27,100,000	$ 30,300,000
Aggregate intrinsic value of the awards outstanding	0
Aggregate intrinsic value of the awards exercisable	$ 0
Weighted average remaining contractual life of awards exercisable	1 year 2 months 12 days
Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	587,711	356,194	402,053
Vesting period	3 years	3 years	3 years
Stock-based compensation expense	$ 23,800,000	$ 28,100,000	$ 19,700,000
Unrecognized compensation related to Awards	$ 23,800,000
Weighted average period	1 year 8 months 12 days
Granted, weighted average grant date fair value	$ 52.29	$ 84.87	$ 71.26
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	343,397	272,052	424,809
Vesting period	3 years	3 years	3 years
Stock-based compensation expense	$ 20,800,000	$ 26,300,000	$ 27,400,000
Unrecognized compensation related to Awards	$ 18,100,000
Weighted average period	1 year 9 months 18 days
Granted, weighted average grant date fair value	$ 55.92	$ 87.34	$ 75.53
Restricted Stock Liability Awards | Non Employee Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	48,000	64,000	18,000
Restricted Stock Liability Awards | Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	295,000	208,000	407,000
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation related to Awards	$ 701,000
Weighted average period	4 months 24 days
Number of fully vested awards and awards expected to vest	1,500,000
Weighted average exercise price of fully vested awards and awards expected to vest	$ 63.72
Weighted average exercise price of fully vested awards and awards expected to vest in years	1 year 3 months 18 days

Stock-based Compensation Plan86

Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	360,415	385,063	349,156
Granted	587,711	356,194	402,053
Vested	(480,253)	(354,237)	(315,535)
Forfeited	(31,109)	(26,605)	(50,611)
Outstanding, Ending Balance	436,764	360,415	385,063
Outstanding, Beginning Balance, weighted average grant date fair value	$ 79.60	$ 68.24	$ 59.08
Granted, weighted average grant date fair value	52.29	84.87	71.26
Vested, weighted average grant date fair value	65.21	72.85	62.43
Forfeited, weighted average grant date fair value	64.73	75.66	65.29
Outstanding, Ending Balance, weighted average grant date fair value	$ 59.74	$ 79.60	$ 68.24
Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	304,504	389,013	423,478
Granted	343,397	272,052	424,809
Vested	(330,870)	(356,413)	(437,570)
Forfeited	(8,294)	(148)	(21,704)
Outstanding, Ending Balance	308,737	304,504	389,013
Outstanding, Beginning Balance, weighted average grant date fair value	$ 80.33	$ 71.02	$ 58.91
Granted, weighted average grant date fair value	55.92	87.34	75.53
Vested, weighted average grant date fair value	68.71	75.52	64.36
Forfeited, weighted average grant date fair value	74.22	77.35	57.31
Outstanding, Ending Balance, weighted average grant date fair value	$ 65.80	$ 80.33	$ 71.02

Stock-based Compensation Plan87

Stock-based Compensation Plans - Stock Option and SARs Activities (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Beginning Balance, Shares	1,966,549	2,582,074	3,433,362
Granted, Shares		1,104	470,617
Exercised, Shares	(427,598)	(616,563)	(1,269,323)
Expired/forfeited, Shares	(27,974)	(66)	(52,582)
Ending Balance, Shares	1,510,977	1,966,549	2,582,074
Beginning Balance, Weighted Average Exercise Price	$ 59.80	$ 56.36	$ 52.52
Granted, Weighted Average Exercise Price		81.74	75.82
Exercised, Weighted Average Exercise Price	45.67	45.45	53.24
Expired/forfeited, Weighted Average Exercise Price	63.10	46.44	53.56
Ending Balance, Weighted Average Exercise Price	$ 63.73	$ 59.80	$ 56.36

Stock-Based Compensation Plan88

Stock-Based Compensation Plans - Summary of SARs Outstanding and Exercisable (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number of outstanding Number of exercisable, Shares	1,510,977
Weighted Average Remaining Contractual Life (in years)	1 year 3 months 18 days
Weighted Average Exercise Price, Outstanding	$ 63.73	$ 59.80	$ 56.36	$ 52.52
Number of exercisable, Shares	1,374,288
Weighted Average Exercise Price, Exercisable	$ 62.53
Range of Exercise Prices One
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	40
Exercise Price, Maximum	$ 49.99
Number of outstanding Number of exercisable, Shares	112,769
Weighted Average Remaining Contractual Life (in years)	1 month 17 days
Weighted Average Exercise Price, Outstanding	$ 49.18
Number of exercisable, Shares	112,769
Weighted Average Exercise Price, Exercisable	$ 49.18
Range of Exercise Prices Two
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	50
Exercise Price, Maximum	$ 59.99
Number of outstanding Number of exercisable, Shares	355,052
Weighted Average Remaining Contractual Life (in years)	4 months 17 days
Weighted Average Exercise Price, Outstanding	$ 52.35
Number of exercisable, Shares	355,052
Weighted Average Exercise Price, Exercisable	$ 52.35
Range of Exercise Prices Three
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	60
Exercise Price, Maximum	$ 69.99
Number of outstanding Number of exercisable, Shares	602,926
Weighted Average Remaining Contractual Life (in years)	1 year 4 months 2 days
Weighted Average Exercise Price, Outstanding	$ 64.19
Number of exercisable, Shares	602,926
Weighted Average Exercise Price, Exercisable	$ 64.19
Range of Exercise Prices Four
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	70
Exercise Price, Maximum	$ 79.99
Number of outstanding Number of exercisable, Shares	438,330
Weighted Average Remaining Contractual Life (in years)	2 years 3 months 11 days
Weighted Average Exercise Price, Outstanding	$ 75.99
Number of exercisable, Shares	301,641
Weighted Average Exercise Price, Exercisable	$ 76.08
Range of Exercise Prices Five
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	80
Exercise Price, Maximum	$ 81.15
Number of outstanding Number of exercisable, Shares	1,900
Weighted Average Remaining Contractual Life (in years)	2 years 8 months 9 days
Weighted Average Exercise Price, Outstanding	$ 81.15
Number of exercisable, Shares	1,900
Weighted Average Exercise Price, Exercisable	$ 81.15

Stock-based Compensation Plan89

Stock-based Compensation Plans - Weighted Average Grant Date Fair Value of SARs (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Weighted Average Assumptions For Fair Values Of Stock Options [Line Items]
Weighted average exercise price per share	$ 81.74	$ 75.82
Expected annual dividend yield	0.20%	0.21%
Expected life in years	4 years 3 months 18 days	3 years 8 months 12 days
Expected volatility	33.00%	35.00%
Risk-free interest rate	1.40%	0.60%
Weighted average grant date fair value per share	$ 23.17	$ 20.20

Stock-based Compensation Plan90

Stock-based Compensation Plans - Additional Information 3 (Detail) - USD ($) $ in Thousands, shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Maximum percentage of employees contribution									75.00%
Maximum percentage of employers contribution in cash									6.00%
Employer contribution									$ 6,100	$ 5,800
Deferred compensation plan vesting period									3 years
Deferred compensation plan	$ (21,016)	$ (43,705)	$ (7,282)	$ (5,624)	$ (36,836)	$ (46,198)	$ 10,519	$ (2,035)	$ (77,627)	$ (74,550)	$ 55,296
Shares held in rabbi trust total	2.8				2.8				2.8	2.8
Vested shares held in rabbi trust	2.5				2.5				2.5	2.5

Supplemental Cash Flow Inform91

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net cash provided from operating activities included:
Income taxes paid to (refunded from) taxing authorities		$ 100	$ (156)	$ (347)
Interest paid		168,826	165,530	159,137
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	[1]	22,184	56,822	76,373
(Decrease) increase in accrued capital expenditures		$ (225,455)	$ 150,604	$ 27,079
[1]	Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MMcf / dMBbls / d	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Commitments And Contingencies Disclosure [Line Items]
Rent expense under operating leases | $	$ 15.9	$ 13.3	$ 13.1
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
2,016
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day | MBbls / d	20
Minimum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	6 years
Maximum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	20 years
Maximum | 2018
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day | MBbls / d	30
Maximum | 2020
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day | MBbls / d	45
Natural Gas | 2026
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	2,000
Natural Gas | 2032
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	1,300
Natural Gas | 2037
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification	400
Natural Gas | 2017 through 2032
Commitments And Contingencies Disclosure [Line Items]
Gathering commitments contingent upon pipeline construction or modification	400
Natural Gas | 2017
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	50
Natural Gas | Minimum | 2019
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	200
Natural Gas | Maximum | 2019
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification per day	300
Ethane | 2031
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification | MBbls / d	20
Propane | 2031
Commitments And Contingencies Disclosure [Line Items]
Transportation commitments contingent upon pipeline construction or modification | MBbls / d	20

Commitments and Contingencies93

Commitments and Contingencies - Future Minimum Lease Commitments (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,016	$ 11,819
2,017	10,014
2,018	8,902
2,019	7,264
2,020	7,238
Thereafter	29,258
Operating Lease Obligations	$ 74,495

Commitments and Contingencies94

Commitments and Contingencies - Schedule of Future Minimum Transportation and Gathering Fees (Detail) $ in Thousands	Dec. 31, 2015USD ($)	[1]
Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]
2,016	$ 407,046
2,017	401,517
2,018	366,914
2,019	366,562
2,020	359,595
Thereafter	1,748,559
Transportation and Gathering Contracts	$ 3,650,193
[1]	The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced.

Commitments and Contingencies95

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2015MMBTU / dbbl / d
2016 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	405,126
2016 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	40,000
2017 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	241,301
2017 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	40,000
2018 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	0
2018 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	40,000
2019 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	0
2019 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000
2020 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	0
2020 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000
2021 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	0
2021 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	20,000
2022 - 2028 | Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d	0
2022 - 2028 | Ethane and Propane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d	15,000

Equity Method Investments - Add

Equity Method Investments - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended		6 Months Ended	12 Months Ended
	Sep. 30, 2013	May. 31, 2007	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2006	Dec. 31, 2015	Jun. 16, 2014
Schedule Of Equity Method Investments [Line Items]
Income (Loss) from equity method investments				$ (3,095)	$ 2,973
Whipstock Natural Gas Services LLC
Schedule Of Equity Method Investments [Line Items]
Percentage ownership interest					50.00%	50.00%
Cash contributed for investment						$ 11,700
Proceeds from sale of equity method investments	$ 7,000
Equity method investment, Realized gain (loss) on disposal	$ 4,400
Nora Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Percentage ownership interest							50.00%
Cash contributed for investment		$ 94,700
Income (Loss) from equity method investments			$ (277)		$ (146)
Reduction in equity to eliminate the profit from gathering and transportation fees			$ 3,100		7,700
Cash distribution from investment				$ 7,000	$ 9,000
EQT Corporation
Schedule Of Equity Method Investments [Line Items]
Equity method investment remaining ownership percentage								50.00%

Office Closing and Exit Costs -

Office Closing and Exit Costs - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost And Reserve [Line Items]
Termination costs	$ 8,780	$ (77)	$ 417	$ 5,950	$ 8,371	$ 15,070	$ 8,371	$ 0
Additional accruals for severance costs						11,706	5,372
Stock-based compensation expense (gain)						217	2,999
Building lease						3,147	$ 0
Oklahoma City Restructuring
Restructuring Cost And Reserve [Line Items]
Additional accruals for severance costs						275
Stock-based compensation expense (gain)						948
Virginia and West Virginia Properties and Other
Restructuring Cost And Reserve [Line Items]
Additional accruals for severance costs						11,400
Stock-based compensation expense (gain)						$ (731)

Office Closing and Exit Costs98

Office Closing and Exit Costs - Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Exit costs included in accrued liabilities in consolidated balance sheet
Beginning balance	$ 5,372
Accrued severance costs	11,706	$ 5,372
Accrued building rent	3,147
Payments	(8,595)
Ending balance	$ 11,630	$ 5,372

Office Closing and Exit Costs99

Office Closing and Exit Costs - Summary of Termination Costs (Detail) - USD ($) $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Of Financial Position [Abstract]
Additional accruals for severance costs						$ 11,706	$ 5,372
Building lease						3,147	0
Stock-based compensation expense (gain)						217	2,999
Total termination costs	$ 8,780	$ (77)	$ 417	$ 5,950	$ 8,371	$ 15,070	$ 8,371	$ 0

Selected Quarterly Financial100

Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Selected Quarterly Financial Information [Line Items]
(Loss) gain on the sale of assets	$ (408,909)	$ (681)	$ 2,909	$ (175)	$ 3,760	$ 167	$ 282,064	$ (353)	$ (406,856)	$ 285,638	$ 92,291
Impairment of proved properties and other assets	87,941	502,233			$ 3,033		24,991		590,174	$ 28,024	$ 7,753
Virginia And West Virginia Property
Selected Quarterly Financial Information [Line Items]
(Loss) gain on the sale of assets	(407,700)								$ (407,700)
Conger Exchange Transaction
Selected Quarterly Financial Information [Line Items]
(Loss) gain on the sale of assets							$ 280,100
Northern Oklahoma and Legacy Shallow Northwest Pennsylvania Assets
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other assets		$ 502,200
Texas Panhandle And South Texas
Selected Quarterly Financial Information [Line Items]
Impairment of proved properties and other assets	$ 87,900

Selected Quarterly Financial101

Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other income:
Natural gas, NGLs and oil sales	$ 254,043	$ 252,065	$ 258,053	$ 325,483	$ 416,388	$ 446,067	$ 477,517	$ 572,017	$ 1,089,644	$ 1,911,989	$ 1,715,676
Derivative fair value income (loss)	126,312	202,004	(34,791)	122,839	412,422	142,057	(24,109)	(146,850)	416,364	383,520	(61,825)
Brokered natural gas, marketing and other	30,372	25,864	21,339	14,485	39,644	28,324	30,052	32,528	92,060	130,548	116,577
Total revenues and other income	410,727	479,933	244,601	462,807	868,454	616,448	483,460	457,695	1,598,068	2,426,057	1,770,428
Costs and expenses:
Direct operating	29,388	35,058	34,780	37,137	37,961	37,792	34,935	39,795	136,363	150,483	128,091
Transportation, gathering and compression	112,481	99,634	95,198	89,426	89,542	84,777	76,809	74,161	396,739	325,289	256,242
Production and ad valorem taxes	7,354	7,336	9,242	9,928	11,923	10,110	10,844	11,678	33,860	44,555	45,240
Brokered natural gas and marketing	34,942	32,331	27,031	21,562	32,370	28,706	34,775	34,129	115,866	129,980	131,786
Exploration	4,260	4,235	5,025	7,886	23,638	11,443	13,621	14,846	21,406	63,548	64,409
Abandonment and impairment of unproved properties	11,432	12,366	12,330	11,491	14,308	13,444	9,332	9,995	47,619	47,079	51,918
General and administrative	43,544	46,178	55,964	48,329	52,363	54,963	56,888	49,212	194,015	213,426	291,171
Termination costs	8,780	(77)	417	5,950	8,371				15,070	8,371	0
Deferred compensation plan	(21,016)	(43,705)	(7,282)	(5,624)	(36,836)	(46,198)	10,519	(2,035)	(77,627)	(74,550)	55,296
Interest	40,849	42,904	43,479	39,207	38,900	39,188	45,488	45,401	166,439	168,977	176,557
Loss on early extinguishment of debt		22,495					24,596		22,495	24,596	12,280
Depletion, depreciation and amortization	127,977	153,993	151,895	147,290	146,539	142,450	133,361	128,682	581,155	551,032	492,397
Impairment of proved properties and other assets	87,941	502,233			3,033		24,991		590,174	28,024	7,753
Loss (gain) on the sale of assets	408,909	681	(2,909)	175	(3,760)	(167)	(282,064)	353	406,856	(285,638)	(92,291)
Total costs and expenses	896,841	915,662	425,170	412,757	418,352	376,508	194,095	406,217	2,650,430	1,395,172	1,620,849
(Loss) income before income taxes	(486,114)	(435,729)	(180,569)	50,050	450,102	239,940	289,365	51,478	(1,052,362)	1,030,885	149,579
Income tax (benefit) expense:
Current	29				(4)		(1)	6	29	1	(143)
Deferred	(164,316)	(134,781)	(61,975)	22,366	166,052	93,522	117,977	18,951	(338,706)	396,502	34,000
Total income tax expense	(164,287)	(134,781)	(61,975)	22,366	166,048	93,522	117,976	18,957	(338,677)	396,503	33,857
Net (loss) income	$ (321,827)	$ (300,948)	$ (118,594)	$ 27,684	$ 284,054	$ 146,418	$ 171,389	$ 32,521	$ (713,685)	$ 634,382	$ 115,722
Net income (loss) per common share:
Basic	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ 1.68	$ 0.87	$ 1.04	$ 0.20	$ (4.29)	$ 3.81	$ 0.71
Diluted	$ (1.93)	$ (1.81)	$ (0.71)	$ 0.16	$ 1.68	$ 0.86	$ 1.04	$ 0.20	$ (4.29)	$ 3.79	$ 0.70

Supplemental Information on 102

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Natural gas and oil properties:
Properties subject to depletion	[1]	$ 8,047,181	$ 9,624,725	$ 8,225,859
Unproved properties	[1]	949,155	943,246	807,022
Total	[1]	8,996,336	10,567,971	9,032,881
Accumulated depletion and depreciation	[1]	(2,635,031)	(2,590,398)	(2,274,444)
Natural gas and oil properties, successful efforts method, net	[1]	$ 6,361,305	$ 7,977,573	$ 6,758,437
[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

Supplemental Information on 103

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Acquisitions	[1],[2]	$ 0	$ 404,252	$ 0
Acreage purchases	[1]	73,025	226,475	137,538
Development	[1]	708,268	1,119,896	938,668
Exploration:
Exploration drilling costs incurred	[1]	87,505	180,925	189,742
Stock-based compensation expense		57,801	70,681	64,369
Gas gathering facilities:
Development	[1]	13,337	13,137	47,086
Subtotal	[1]	903,541	2,008,233	1,377,443
Asset retirement obligations	[1]	22,184	56,822	76,373
Total costs incurred	[1]	925,725	2,065,055	1,453,816
Expense
Exploration:
Exploration costs incurred	[1]	18,421	58,979	60,384
Stock-based compensation expense	[1]	$ 2,985	$ 4,569	$ 4,025
[1]	Includes cost incurred whether capitalized or expensed.
[2]	See also Note 3 for additional information related to the 2014 Conger Exchange which includes $134.8 million of gas gathering assets received in the exchange and $11.9 million of asset retirement obligations added in the exchange.

Supplemental Information on 104

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Parenthetical) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Acquisition Costs, Period Cost	[1],[2]	$ 0	$ 404,252	$ 0
Asset retirement obligations	[1]	$ 22,184	56,822	$ 76,373
Conger Exchange Transaction
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Asset retirement obligations			11,900
Gas Gathering Assets
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Acquisition Costs, Period Cost			$ 134,800
[1]	Includes cost incurred whether capitalized or expensed.
[2]	See also Note 3 for additional information related to the 2014 Conger Exchange which includes $134.8 million of gas gathering assets received in the exchange and $11.9 million of asset retirement obligations added in the exchange.

Supplemental Information on 105

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Additional Information (Detail) $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls	Dec. 31, 2014MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls	Dec. 31, 2013MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls	Dec. 31, 2012MMcfeMMcfMBbls
Reserve Quantities [Line Items]
Percentage of proved resources reviewed by consultant		94.00%
Statement That Reserve Estimates Differ From Auditors		more than 10%
Proved Reserve And Pretax Present Value of Reserve Discounted		10.00%
Variance in reserve estimates		less than 5%.
Scheduled to be drilling period maximum for undeveloped reserves		Scheduled to be drilled within five years
Reserve attributable to natural gas		80.00%	58.00%	49.00%
Improved recoveries		781,000	449,600	630,300
Proved undeveloped reserves dropped		1,200,000	611,000
Cost spent on undeveloped reserves transferred to developed reserves | $		$ 398.8
Estimated future development costs in 2016 | $		435.6
Estimated future development costs in 2017 | $		509,400
Estimated future development costs in 2018 | $		$ 471.6
Crude Oil and NGL
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / bbl		50.13	94.42	97.33
Crude Oil
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		35.07	79.04	86.66
Proved developed and undeveloped reserves | MBbls		53,193	48,658	48,360	45,082
NGLs
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / bbl		11.74	27.20	25.93
Proved developed and undeveloped reserves | MBbls		549,135	515,907	374,412	240,399
Natural Gas
Reserve Quantities [Line Items]
Estimate reserve information average realized prices | $ / Mcf		2.07	4.14	3.75
Proved developed and undeveloped reserves | MMcf		6,277,697	6,922,836	5,665,645	4,792,676
Natural Gas, Per Thousand Cubic Feet
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices | $ / MMBTU		2.59	4.35	3.67
Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved reserves from drilling activities and evaluations of proved areas	[1]	1,265,348	2,398,709	1,732,944
Proved developed and undeveloped reserve balances	[1]	9,891,663	10,310,229	8,202,274	6,505,570
Revisions of previous estimates	[1]	(211,163)	90,822	448,898
Ethane and Natural Gas Equivalents
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve balances		1,296,000	1,170,000	676,000
Ethane Reserves and NGLs
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves | MBbls		292,800	264,300	155,800
[1]	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 indicative of the relationship of oil and natural gas prices.

Supplemental Information on 106

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Proved Developed and Undeveloped Reserves (Detail)		12 Months Ended
		Dec. 31, 2015MMcfeMMcfMBbls	Dec. 31, 2014MMcfeMMcfMBbls	Dec. 31, 2013MMcfeMMcfMBbls
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe		4,469,588	4,960,468
Natural Gas
Reserve Quantities [Line Items]
Beginning Balance | MMcf		6,922,836	5,665,645	4,792,676
Revisions | MMcf		(340,286)	(30,566)	384,825
Extensions, discoveries and additions | MMcf		1,017,956	1,393,108	853,746
Purchases | MMcf		0	262,813	0
Property sales | MMcf		(960,122)	(81,238)	(101,074)
Production | MMcf		(362,687)	(286,926)	(264,528)
Ending Balance | MMcf		6,277,697	6,922,836	5,665,645
Proved developed reserves:
Proved developed reserves | MMcf		3,376,165	3,583,051	2,797,483
Proved undeveloped reserves:
Proved undeveloped reserves | MMcf		2,901,533	3,339,785	2,868,162
NGLs
Reserve Quantities [Line Items]
Beginning Balance		515,907	374,412	240,399
Revisions		17,717	19,716	7,743
Extensions, discoveries and additions		36,308	154,664	135,810
Purchases		0	0	0
Property sales		(441)	(14,064)	(286)
Production		(20,356)	(18,821)	(9,254)
Ending Balance		549,135	515,907	374,412
Proved developed reserves:
Proved developed reserves		309,306	270,271	206,477
Proved undeveloped reserves:
Proved undeveloped reserves		239,828	245,636	167,935
Crude Oil and Condensate
Reserve Quantities [Line Items]
Beginning Balance		48,658	48,360	45,082
Revisions		3,804	515	2,935
Extensions, discoveries and additions		4,924	12,936	10,723
Purchases		0	0	0
Property sales		(109)	(9,083)	(6,553)
Production		(4,084)	(4,070)	(3,827)
Ending Balance		53,193	48,658	48,360
Proved developed reserves:
Proved developed reserves		31,679	24,180	26,054
Proved undeveloped reserves:
Proved undeveloped reserves		21,514	24,478	22,306
Natural Gas Equivalents
Proved developed reserves:
Proved developed reserves | MMcfe	[1]	5,422,075	5,349,761	4,192,666
Proved undeveloped reserves:
Proved undeveloped reserves | MMcfe	[1]	4,469,588	4,960,468	4,009,608
Beginning Balance | MMcfe	[1]	10,310,229	8,202,274	6,505,570
Revisions | MMcfe	[1]	(211,163)	90,822	448,898
Extensions, discoveries and additions | MMcfe	[1]	1,265,348	2,398,709	1,732,944
Purchases | MMcfe	[1]	0	262,813	0
Property sales | MMcfe	[1]	(963,423)	(220,122)	(142,116)
Production | MMcfe	[1]	(509,328)	(424,267)	(343,022)
Ending Balance | MMcfe	[1]	9,891,663	10,310,229	8,202,274
[1]	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 indicative of the relationship of oil and natural gas prices.

Supplemental Information on 107

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Detail)	12 Months Ended
	Dec. 31, 2015MMcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves at December 31, 2014	4,960,468
Undeveloped reserves transferred to developed	(762,936)
Revisions	(441,874)	[1]
Purchases/(sales)	(201,809)
Extension and discoveries	915,739
Ending proved undeveloped reserves at December 31, 2015	4,469,588
[1]	Includes 1.2 Tcfe of proved undeveloped reserves dropped due to the five year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan.

Supplemental Information on 108

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Parenthetical) (Detail) - MMcfe	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Proved undeveloped reserves dropped	1,200,000	611,000

Supplemental Information on 109

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows		$ 21,290,873	$ 46,507,646
Future costs:
Production		(10,411,360)	(15,239,210)
Development	[1]	(2,213,582)	(4,275,693)
Future net cash flows before income taxes		8,665,931	26,992,743
Future income tax expense		(2,007,794)	(8,900,383)
Total future net cash flows before 10% discount		6,658,137	18,092,360
10% annual discount		(3,932,274)	(10,499,333)
Standardized measure of discounted future net cash flows		$ 2,725,863	$ 7,593,027	$ 5,862,231	$ 3,223,805
[1]	2015 includes $384.5 million of undiscounted future asset retirement costs estimated as of December 31, 2015, using current estimates of future abandonment costs.

Supplemental Information on 110

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Extractive Industries [Abstract]
Undiscounted future asset retirement costs estimation	$ 384.5

Supplemental Information on 111

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revisions of previous estimates
Changes in prices and production costs	$ (7,231,629)	$ 5,069	$ 2,172,704
Revisions in quantities	(868,886)	102,760	513,168
Changes in future development and abandonment costs	359,540	(407,688)	(275,468)
Net change in income taxes	2,173,904	(441,935)	(1,299,227)
Accretion of discount	1,007,027	789,754	395,989
Purchases of reserves in place	0	297,358	0
Additions to proved reserves from extensions, discoveries and improved recovery	486,478	2,713,999	1,981,054
Natural gas, NGLs and oil sales, net of production costs	(522,682)	(1,391,663)	(1,286,103)
Development costs incurred during the period	1,033,539	755,384	462,862
Sales of reserves in place	(1,050,237)	(249,055)	(162,463)
Timing and other	(254,218)	(443,187)	135,910
Net change for the year	(4,867,164)	1,730,796	2,638,426
Beginning of year	7,593,027	5,862,231	3,223,805
End of year	$ 2,725,863	$ 7,593,027	$ 5,862,231