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Total current liabilities

15,067

5,037

Accrued liabilities

187,973

161,520

Accrued interest

39,695

44,375

Derivative liabilities

26,198

Deferred tax liabilities

115,587

755,264

495,561

Bank debt

723,000

500,000

Subordinated notes

2,350,000

2,640,516

Deferred tax liabilities

997,494

771,980

Derivative liabilities

Deferred compensation liabilities

178,599

247,537

Asset retirement obligations and other liabilities

284,994

229,015

Total liabilities

5,289,351

4,884,634

Commitments and contingencies

Stockholders' Equity

Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding

Common stock, $0.01 par 475,000,000 shares authorized, 168,711,131 issued at December 31, 2014 and 163,441,414 issued at December 31, 2013

1,687

1,634

Common stock held in treasury, 82,954 shares at December 31, 2014 and 98,520 shares at December 31, 2013

(3,088)

(3,637)

Additional paid-in capital

2,400,475

1,959,636

Retained earnings

1,058,355

450,583

Accumulated other comprehensive income

6,236

Total stockholders' equity

3,457,429

2,414,452

Total liabilities and stockholders' equity

$ 8,746,780

$ 7,299,086

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Statement Of Financial Position [Abstract]
Allowance for doubtful accounts on accounts receivable	$ 2,719	$ 2,494
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	168,711,131	163,441,414
Common stock held in treasury, shares	82,954	98,520

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and other income:
Natural gas, NGLs and oil sales	$ 416,388	$ 446,067	$ 477,517	$ 572,017	$ 448,545	$ 431,214	$ 437,678	$ 398,239	$ 1,911,989	$ 1,715,676	$ 1,351,694
Derivative fair value income (loss)	412,422	142,057	(24,109)	(146,850)	(59,355)	(40,355)	137,760	(99,875)	383,520	(61,825)	41,437
Gain on the sale of assets	3,760	167	282,064	(353)	3,162	6,008	83,287	(166)	285,638	92,291	49,132
Brokered natural gas, marketing and other	39,644	28,324	30,052	32,528	35,734	45,171	14,631	21,041	130,548	116,577	15,441
Total revenues and other income	872,214	616,615	765,524	457,342	428,086	442,038	673,356	319,239	2,711,695	1,862,719	1,457,704
Costs and expenses:
Direct operating	37,961	37,792	34,935	39,795	34,360	30,907	32,636	30,188	150,483	128,091	115,905
Transportation, gathering and compression	89,542	84,777	76,809	74,161	66,820	60,958	66,048	62,416	325,289	256,242	192,445
Production and ad valorem taxes	11,923	10,110	10,844	11,678	11,290	11,454	11,113	11,383	44,555	45,240	67,120
Brokered natural gas and marketing	32,370	28,706	34,775	34,129	41,692	51,117	16,662	22,315	129,980	131,786	20,434
Exploration	23,638	11,443	13,621	14,846	14,065	20,496	13,068	16,780	63,548	64,409	69,807
Abandonment and impairment of unproved properties	14,308	13,444	9,332	9,995	5,852	11,692	19,156	15,218	47,079	51,918	125,278
General and administrative	52,363	54,963	56,888	49,212	60,207	44,919	101,987	84,058	213,426	291,171	173,813
Termination costs	8,371								8,371
Deferred compensation plan	(36,836)	(46,198)	10,519	(2,035)	22,039	(2,225)	(6,878)	42,360	(74,550)	55,296	7,203
Interest expense	38,900	39,188	45,488	45,401	44,955	44,321	45,071	42,210	168,977	176,557	168,798
Loss on early extinguishment of debt			24,596				12,280		24,596	12,280	11,063
Depletion, depreciation and amortization	146,539	142,450	133,361	128,682	126,958	130,343	119,995	115,101	551,032	492,397	445,228
Impairment of proved properties and other assets	3,033		24,991			7,012	741		28,024	7,753	35,554
Total costs and expenses	422,112	376,675	476,159	405,864	428,238	410,994	431,879	442,029	1,680,810	1,713,140	1,432,648
Income before income taxes	450,102	239,940	289,365	51,478	(152)	31,044	241,477	(122,790)	1,030,885	149,579	25,056
Income tax expense (benefit):
Current	(4)		(1)	6	(143)		(25)	25	1	(143)	(1,778)
Deferred	166,052	93,522	117,977	18,951	(28,180)	11,866	97,519	(47,205)	396,502	34,000	13,832
Total income tax expense	166,048	93,522	117,976	18,957	(28,323)	11,866	97,494	(47,180)	396,503	33,857	12,054
Net income	$ 284,054	$ 146,418	$ 171,389	$ 32,521	$ 28,171	$ 19,178	$ 143,983	$ (75,610)	$ 634,382	$ 115,722	$ 13,002
Net income per common share:
Basic	$ 1.68	$ 0.87	$ 1.04	$ 0.20	$ 0.17	$ 0.12	$ 0.88	$ (0.47)	$ 3.81	$ 0.71	$ 0.08
Diluted	$ 1.68	$ 0.86	$ 1.04	$ 0.20	$ 0.17	$ 0.12	$ 0.88	$ (0.47)	$ 3.79	$ 0.70	$ 0.08
Weighted average common shares outstanding:
Basic									163,625	160,438	159,431
Diluted									164,403	161,407	160,307

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Statement Of Income And Comprehensive Income [Abstract]

Net income

$ 634,382

$ 115,722

$ 13,002

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]

(14,840)

(144,434)

De-designated hedges reclassified into natural gas, NGLs and oil sales, net of taxes

^[2]

(6,236)

(56,254)

De-designated hedges reclassified to derivative fair value, net of taxes

^[3]

(2,376)

Change in unrealized deferred hedging (losses) gains, net of taxes

^[4]

(4,203)

71,716

Total comprehensive income (loss)

$ 628,146

$ 38,049

$ (59,716)

[1]	Amounts are net of income tax benefit of $9,488 for the year ended December 31, 2013 compared to $91,871 for the year ended December 31, 2012.
[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 compared to income tax expense of $47,466 for the year ended December 31, 2012.

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	$ 91,871
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	$ (47,466)

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income	$ 634,382,000	$ 115,722,000	$ 13,002,000
Adjustments to reconcile net income to net cash provided from operating activities:
Loss (gain) from equity method investments, net of distributions	3,095,000	(2,973,000)	5,670,000
Deferred income tax expense	396,502,000	34,000,000	13,832,000
Depletion, depreciation and amortization and impairment	579,056,000	500,150,000	480,782,000
Exploration dry hole and impairment costs	16,145,000	5,699,000	841,000
Abandonment and impairment of unproved properties	47,079,000	51,918,000	125,278,000
Derivative fair value (income) loss	(383,520,000)	61,825,000	(41,437,000)
Cash settlements on derivative financial instruments that do not qualify for hedge accounting	(42,634,000)	(31,256,000)	38,700,000
Allowance for bad debt	250,000	250,000	750,000
Amortization of deferred financing costs, loss on extinguishment of debt and other	24,694,000	23,866,000	23,165,000
Deferred and stock-based compensation	(4,295,000)	119,398,000	60,136,000
Gain on the sale of assets	(285,638,000)	(92,291,000)	(49,132,000)
Changes in working capital:
Accounts receivable	(5,329,000)	(21,212,000)	(38,017,000)
Inventory and other	(4,521,000)	3,785,000	(7,376,000)
Accounts payable	(1,023,000)	(13,555,000)	13,654,000
Accrued liabilities and other	(20,108,000)	(11,788,000)	7,251,000
Net cash provided from operating activities	954,135,000	743,538,000	647,099,000
Investing activities:
Additions to natural gas and oil properties	(1,200,419,000)	(1,159,252,000)	(1,498,628,000)
Additions to field service assets	(11,863,000)	(5,925,000)	(4,762,000)
Acreage purchases	(211,971,000)	(132,145,000)	(191,065,000)
Equity method investments	1,103,000	3,799,000
Proceeds from disposal of assets	180,508,000	315,522,000	168,219,000
Purchases of marketable securities held by the deferred compensation plan	(30,898,000)	(36,136,000)	(60,406,000)
Proceeds from the sales of marketable securities held by the deferred compensation plan	28,084,000	30,701,000	58,084,000
Net cash used in investing activities	(1,245,456,000)	(983,436,000)	(1,528,558,000)
Financing activities:
Borrowings on credit facilities	2,107,000,000	1,684,000,000	1,773,000,000
Repayments on credit facilities	(1,884,000,000)	(1,923,000,000)	(1,221,000,000)
Issuance of subordinated notes		750,000,000	600,000,000
Repayment of subordinated notes	(312,000,000)	(259,063,000)	(259,375,000)
Dividends paid	(26,610,000)	(26,129,000)	(25,981,000)
Debt issuance costs	(8,866,000)	(12,448,000)	(12,605,000)
Issuance of common stock	396,562,000	343,000	2,073,000
Change in cash overdrafts	3,371,000	5,610,000	(1,126,000)
Proceeds from the sales of common stock held by the deferred compensation plan	15,964,000	20,681,000	26,633,000
Net cash provided from financing activities	291,421,000	239,994,000	881,619,000
Increase in cash and cash equivalents	100,000	96,000	160,000
Cash and cash equivalents at beginning of year	348,000	252,000	92,000
Cash and cash equivalents at end of year	$ 448,000	$ 348,000	$ 252,000

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, 2011	$ 2,392,420	$ 1,613	$ (6,343)	$ 1,866,554	$ 373,969	$ 156,627
Beginning balance Shares at Dec. 31, 2011		161,303,000
Issuance of common stock	20,264	$ 13		20,251
Issuance of common stock, shares		1,339,000
Stock-based compensation expense	30,405			30,405
Common dividends declared ($0.16 per share)	(25,981)				(25,981)
Treasury stock issuance			1,583	(1,583)
Other comprehensive income (loss)	(72,718)					(72,718)
Net income	13,002				13,002
Ending balance at Dec. 31, 2012	2,357,392	$ 1,626	(4,760)	1,915,627	360,990	83,909
Ending balance Shares at Dec. 31, 2012		162,642,000
Issuance of common stock	9,289	$ 8		9,281
Issuance of common stock, shares		799,000
Stock-based compensation expense	35,851			35,851
Common dividends declared ($0.16 per share)	(26,129)				(26,129)
Treasury stock issuance			1,123	(1,123)
Other comprehensive income (loss)	(77,673)					(77,673)
Net income	115,722				115,722
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	163,441,414	163,441,414
Issuance of common stock	$ 398,607	$ 53		398,554
Issuance of common stock, shares		5,270,000
Stock-based compensation expense	42,834			42,834
Common dividends declared ($0.16 per share)	(26,610)				(26,610)
Treasury stock issuance			549	(549)
Other comprehensive income (loss)	(6,236)					$ (6,236)
Net income	634,382				634,382
Ending balance at Dec. 31, 2014	$ 3,457,429	$ 1,687	$ (3,088)	$ 2,400,475	$ 1,058,355
Ending balance Shares at Dec. 31, 2014	168,711,131	168,711,131

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

Summary of Significant Accounting Policies

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended												12 Months Ended
	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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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 Nature of Business	12 Months Ended
Summary of Organization and Nature of Business	Dec. 31, 2014
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 and Midcontinent regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

(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 income. As of June 16, 2014, we no longer have income or loss from 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.

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 ancillary to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

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

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 Financial Accounting Standard Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we receive a price from the purchaser (which is net of processing costs) which is recorded in revenue at the net price we receive. Under the other arrangement, 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 revenue and expense in accordance with applicable accounting standards. In 2013, we purchased (and sold) natural gas which was used to blend our rich residue gas from the Southwest Marcellus Shale. In 2014, we also reported a margin from the release of transportation capacity where we have taken firm transportation ahead of our production volumes. Our brokered margin was a gain of $9.4 million in 2014 compared to a loss of $5.7 million in 2013. The amount of brokered margin was immaterial in 2012.

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 $2.7 million at December 31, 2014 compared to $2.5 million at December 31, 2013. We recorded bad debt expense of $250,000 in both the year ended December 31, 2014 and 2013 compared to $750,000 in 2012.

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. At December 31, 2014, we had recorded a net liability of $52,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance.

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 $11.8 million of materials and supplies at December 31, 2014 compared to $9.6 million at December 31, 2013. Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations. At December 31, 2014, we also had propane commodity inventory of $2.0 million, which is carried at lower of average cost or market, on a first-in, first-out basis. We had no commodity inventory as of December 31, 2013.

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 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 $943.2 million as of December 31, 2014 compared to $807.0 million in 2013. We have recorded abandonment and impairment expense related to unproved properties of $47.1 million in the year ended December 31, 2014 compared to $51.9 million in 2013 and $125.3 million in 2012.

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.

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 income 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 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 $12.9 million in the year ended December 31, 2014 compared to $13.2 million in both 2013 and 2012.

Other Assets

The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity or modifications significantly change the cash flows, the related unamortized costs are expensed. Other assets at December 31, 2014 include $42.2 million of unamortized debt issuance costs, $68.5 million of marketable securities held in our deferred compensation plans and $10.3 million of other investments including surface acreage. Other assets at December 31, 2013 include $44.5 million of unamortized debt issuance costs, $67.8 million of marketable securities held in our deferred compensation plans and $9.0 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 the Monte Carlo simulation method. The 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. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying consolidated statements of income.

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 its 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 income. At times, we have also entered into basis swap agreements, which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments.

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 amounts 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, 2014, 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 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 guaranties, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for uncollectible receivables was $2.7 million at December 31, 2014 compared to $2.5 million at December 31, 2013.

For the year ended December 31, 2014, we had four customers that accounted for 10% or more of total natural gas, NGLs and oil sales. For the year ended December 31, 2013, we had four customers that accounted for 10% or more of total natural gas, NGLs and oil sales. For the year ended December 31, 2012, we had two 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 Range to fund or post additional collateral prior to the scheduled cash settlement date.

At December 31, 2014, our derivative counterparties included fifteen financial institutions, of which all but one are secured lenders in our bank credit facility. At December 31, 2014, our net derivative asset includes a receivable from the counterparty not included in our bank credit facility totaling $30.3 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 Range’s 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.

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 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.

Accumulated Other Comprehensive Income

The following details the components of AOCI and related tax effects for the three years ended December 31, 2014. Amounts included in AOCI exclusively relate to our derivative activity. See footnote 10 for additional information on the discontinuance of hedge accounting (in thousands).

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2011	$	254,678		$	(98,051	)	$	156,627
Contract settlements reclassified to income		(236,305	)		91,871			(144,434	)
Change in unrealized deferred hedging gains		119,182			(47,466	)		71,716
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 losses		(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

Accounting Pronouncements Implemented

Recently Adopted

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of (1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and (2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in first quarter 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption was permitted and we adopted this new standard in first quarter 2014 which did not have an impact on our consolidated results of operations, financial position or cash flows.

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 is permitted but only for disposals (or classifications that are held for sale) that have 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, is not reported as a discontinued operation.

Accounting Pronouncements Not Yet Adopted

In May 2014, an accounting standards update was issued for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition” and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for us for the reporting period beginning January 1, 2017, with early application not permitted. Entities have the option of using either a full retrospective or modified approach to adopt this new standard. We are evaluating our existing revenue recognition policies to determine whether any contracts will be affected by the new requirements.

In August 2014, the Financial Accounting Standards Board (“FASB”) issued an update 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 any impact on our consolidated results of operations, financial position or cash flows.

Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisitions and Dispositions

(3)	ACQUISITIONS AND 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 other EQT assets in Virginia and $145.0 million in cash, before closing adjustments (the “Conger Exchange”). We closed the exchange transaction on June 16, 2014. The assets exchanged met the definition of a business under accounting standards and was recorded at fair value. We recognized a pre-tax gain of $272.7 million related to this exchange, after selling expenses of $5.0 million, which is recognized as a gain on sale of assets in our consolidated statements of income 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 net income (defined as natural gas, oil and NGLs sales and net brokered margin, less direct operating expenses, production and ad valorem taxes and transportation expenses), compared to $48.7 million in the year ended December 31, 2013 and $40.2 million in the year ended December 31, 2012 for our Conger assets. The combined carrying amount of our Conger assets prior to the exchange was $271.8 million. The following table presents the fair value of assets acquired and liabilities assumed in the transaction (in thousands):


	Conger Exchange
Consideration
Fair value of net assets transferred	$	550,273

Fair value of assets acquired and liabilities assumed
Cash	$	151,675
Working capital – Nora Gathering, LLC		12,731
Natural gas and oil properties		402,176
Transportation and field assets		7,793
Other liabilities-firm transportation contract		(12,175	)
Asset retirement obligations		(11,927	)
Fair value of net assets acquired and liabilities assumed	$	550,273

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 16, 2014, we have 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 income for the year ended December 31, 2014. We assumed trade receivables as part of the acquisition of NGLLC of $5.5 million, all of which we collected.

For the period from June 16, 2014 through December 31, 2014, we recognized $33.8 million of natural gas, oil and NGLs sales and we recognized $25.7 million of field net operating income (defined as natural gas, oil and NGLs sales less direct operating expenses, production and ad valorem taxes and transportation expenses) 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.

Dispositions

We recognized an aggregate gain on the sale of assets of $285.6 million in the year ended December 31, 2014 compared to $92.3 million in 2013 and $49.1 million in 2012. The following describes the significant divestitures that are included in income from operations:

—	As detailed above, we completed the Conger Exchange in June 2014 and we recognized a pre-tax gain of $287.7 million, before selling expenses of $5.0 million, which includes a $10.0 million gain on the remeasurement of our membership interest in NGLLC.

—	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 pre-tax gain of $83.3 million, before selling expenses of $4.2 million.

—	In November 2012, we completed the sale of our Ardmore Woodford properties in Southern Oklahoma for cash proceeds of $135.0 million and we recognized a pre-tax gain of $55.2 million related to this sale.

—	During 2014, 2013 and 2012, we sold miscellaneous proved and unproved oil and gas properties, inventory, and other property and equipment and recorded a pre-tax gain of $2.9 million in 2014, compared to a pre-tax gain of $13.2 million in 2013 and a pre-tax loss of $6.1 million in 2012.

Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

(4)	INCOME TAXES

Our income tax expense was $396.5 million for the year ended December 31, 2014 compared to $33.9 million in 2013 and $12.1 million in 2012. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2014		2013			2012
Federal statutory tax rate	35.0	%		35.0	%		35.0	%
State	3.1			(2.3	)		0.7
State apportionment rate change	(0.2	)		(14.9	)		¾
Non-deductible executive compensation	0.2			0.7			1.4
Valuation allowances	0.2			3.5			8.8
Other	0.2			0.6			2.2
Consolidated effective tax rate	38.5	%		22.6	%		48.1	%

Income tax expense (benefit) attributable to income before income taxes consists of the following (in thousands):

		2014						2013									2012
		Current	Deferred		Total		Current			Deferred			Total			Current			Deferred		Total
U.S. federal	$	¾	$	361,152	$	361,152	$	¾		$	58,527		$	58,527		$	—		$	11,873	$	11,873
U.S. state and local		1		35,350		35,351		(143	)		(24,527	)		(24,670	)		(1,778	)		1,959		181
Total	$	1	$	396,502	$	396,503	$	(143	)	$	34,000		$	33,857		$	(1,778	)	$	13,832	$	12,054

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

	December 31,
	2014			2013
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	9,286		$	9,128
Current portion of asset retirement obligation		5,745			1,854
Cumulative mark-to-market loss		584			15,193
Net operating loss carryforward		—			23,079
Other		9,921			7,936
Total current		25,536			57,190
Non-current
Net operating loss carryforward		176,812			57,266
Deferred compensation		64,656			91,094
Equity compensation		25,833			22,800
AMT credits and other credits		4,447			4,122
Non-current portion of asset retirement obligation		104,063			86,126
Cumulative mark-to-market loss		65			¾
Other		987			1,116
Valuation allowance		(16,599	)		(14,781	)
Total non-current		360,264			247,743
Deferred tax liabilities:
Current
Net gain in AOCI related to hedge derivatives		—			(3,987	)
Other		(2,350	)		(1,789	)
Cumulative mark-to-market gain		(138,773	)		¾
Total current		(141,123	)		(5,776	)
Non-current
Depreciation, depletion and investments		(1,342,039	)		(1,010,757	)
Cumulative mark-to-market gain		(15,410	)		(6,424	)
Other		(310	)		(2,542	)
Total non-current		(1,357,759	)		(1,019,723	)
Net deferred tax liability	$	(1,113,082	)	$	(720,566	)

At December 31, 2014, deferred tax liabilities exceeded deferred tax assets by $1.1 billion. As of December 31, 2014, we have a $7.8 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to certain executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m). We also have an $8.8 million valuation allowance on our Oklahoma net operating loss carryforwards.

At December 31, 2014, we had regular net operating loss (“NOL”) carryforwards of $641.4 million and alternative minimum tax (“AMT”) NOL carryforwards of $557.3 million that expire between 2018 and 2034. Our federal deferred tax asset related to regular NOL carryforwards at December 31, 2014 was $130.8 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, 2014, 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 2011 and after and we are subject to various state tax examinations for years 2010 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, 2014. Throughout 2014, our unrecognized tax benefits were not material.

Net Income Per Common Share

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Net Income Per Common Share

(5)	NET INCOME PER COMMON SHARE

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


	Year Ended December 31,
	2014			2013			2012
Net income, as reported	$	634,382		$	115,722		$	13,002
Participating basic earnings ^(a)		(10,725	)		(1,975	)		(460	)
Basic net income attributed to common shareholders		623,657			113,747			12,542
Reallocation of participating earnings ^(a)		48			9			—
Diluted net income attributed to common shareholders	$	623,705		$	113,756		$	12,542
Net income per common share:
Basic	$	3.81		$	0.71		$	0.08
Diluted	$	3.79		$	0.70		$	0.08

^(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,
	2014	2013		2012
Denominator:
Weighted average common shares outstanding – basic	163,625		160,438		159,431
Effect of dilutive securities:
Director and employee SARs and restricted stock Equity Awards	778		969		876
Weighted average common shares outstanding – diluted	164,403		161,407		160,307

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 both periods ending December 31, 2014 and December 31, 2013 and 2.9 million shares for the period ending December 31, 2012. SARs of 1,900 for the year ended December 31, 2014 compared to 226,000 in 2013 and 854,000 in 2012 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

Suspended Exploratory Well Costs

12 Months Ended

Dec. 31, 2014

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 income. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2014, 2013 and 2012 (in thousands, except for number of projects):

	2014			2013			2012
Balance at beginning of period	$	6,964		$	57,360		$	93,388
Additions to capitalized exploratory well costs pending the determination of proved reserves		18,747			39,832			153,250
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(15,735	)		(84,840	)		(184,298	)
Divested wells		¾			¾			(4,980	)
Capitalized exploratory well costs charged to expense		(6,980	)		(5,388	)		—
Balance at end of period		2,996			6,964			57,360
Less exploratory well costs that have been capitalized for a period of one year or less		(2,996	)		¾			(45,965	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	¾		$	6,964		$	11,395
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		¾			1			5

Indebtedness

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Indebtedness

(7)	INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2014 is shown parenthetically) (in thousands). No interest was capitalized during 2014, 2013, and 2012.

	December 31,
	2014		2013
Bank debt (2.0%)	$	723,000	$	500,000
Senior subordinated notes:
8.00% senior subordinated notes due 2019, net of $9,484 discount		¾		290,516
6.75% senior subordinated notes due 2020		500,000		500,000
5.75% senior subordinated notes due 2021		500,000		500,000
5.00% senior subordinated notes due 2022		600,000		600,000
5.00% senior subordinated notes due 2023		750,000		750,000
Total debt	$	3,073,000	$	3,140,516

Bank Debt

On October 16, 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 and an initial borrowing base of $3.0 billion. On December 31, 2014, bank commitments totaled $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually each May and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-nine financial institutions, with no one bank holding more than 6% 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, 2014, the outstanding balance under the bank credit facility was $723.0 million with $105.3 million of undrawn letters of credit leaving $1.2 billion of borrowing capacity available under the commitment amount. During a non-investment grade period, borrowings under the bank facility can either be at the alternate base rate (“ABR,” as defined) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to ABR loans or to convert all or any of the ABR loans to LIBOR loans. The weighted average interest rate was 2.0% for each of the years ended December 31, 2014 and 2013 and 2.2% for the year ended December 31, 2012. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At December 31, 2014, the commitment fee was 0.30%, the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.

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 borrowings 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%.

Senior Subordinated Notes

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

Early Extinguishment of Debt

In 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.

In 2012, we called our 7.5% senior subordinated notes due 2017 at 103.75% of par which we redeemed on December 28, 2012. In fourth quarter 2012, we recognized an $11.1 million loss on extinguishment of debt, including transaction call premium costs as well as expensing of the remaining deferred financing cost on repurchased debt.

Guarantees

Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly owned subsidiaries, which are directly or indirectly owned by Range, of 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 debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. During an investment grade period in which Range has only one investment grade rating, an additional covenant is imposed whereby 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 to 1.0. We were in compliance with applicable covenants under the bank credit facility at December 31, 2014.

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, 2014, we were in compliance with these covenants.

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2014 (in thousands):

	Year Ended December 31,
2015	$	—
2016		—
2017		—
2018		—
2019		723,000
Thereafter		2,350,000
	$	3,073,000

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(8)	ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2014 and 2013 are as follows (in thousands):


	2014			2013
Beginning of period	$	230,077		$	146,478
Liabilities incurred		8,602			8,731
Acquisitions		11,927			¾
Liability released		(8,309	)		¾
Liabilities settled		(4,442	)		(424	)
Disposition of wells		(13,951	)		(3,129	)
Accretion expense		15,226			10,778
Change in estimate		48,333			67,643
End of period		287,463			230,077
Less current portion		(15,067	)		(5,037	)
Long-term asset retirement obligations	$	272,396		$	225,040

Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying consolidated statements of income.

Capital Stock

12 Months Ended

Dec. 31, 2014

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 2012:


	Year Ended December 31,
	2014		2013		2012
Beginning balance		163,342,894		162,514,098		161,131,547
Equity offering		4,560,000		−		−
Stock options/SARs exercised		195,242		278,916		926,425
Restricted stock grants		270,062		401,122		354,674
Restricted stock units vested		244,413		119,480		57,824
Treasury shares		15,566		29,278		43,628
Ending balance		168,628,177		163,342,894		162,514,098

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2014, 2013 and 2012. 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.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative Activities

12 Months Ended

Dec. 31, 2014

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 pre-tax gain of $401.7 million at December 31, 2014. These contracts expire monthly through December 2016. The following table sets forth the derivative volumes by year as of December 31, 2014:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2015	Collars	145,000 Mmbtu/day	$4.07–$4.56
2015	Swaps	412,390 Mmbtu/day	$4.15
2016	Swaps	120,000 Mmbtu/day	$4.15
Crude Oil
2015	Swaps	9,626 bbls/day	$90.57
2016	Swaps	1,000 bbls/day	$91.43
NGLs (C3 - Propane)
2015	Swaps	2,245 bbls/day	$0.95/gallon

NGLs (C5 - Natural Gasoline)
2015-First Quarter		Swaps		500 bbls/day		$2.14/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 accompanying consolidated balance sheets, which 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.

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 $116.5 million in 2013 and $236.3 million in 2012 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 income. The ineffective portion is calculated as the difference between the changes in fair value of the derivative and the estimated change in future cash flows from the item hedged. Derivative fair value 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 and gains of $1.1 million in the year ended December 31, 2012.

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 marked-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.

With the election to de-designate hedging instruments, 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 marked-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.

Basis Swap Contracts

At December 31, 2014, we had natural gas basis swap contracts that are not designated for hedge accounting, which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts are for 35,164 Mmbtu/day and settle monthly through October 2015. The fair value of these contracts was a gain of $1.7 million on December 31, 2014.

Derivative assets and liabilities

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2014 and 2013 is summarized below. As of December 31, 2014, we are conducting derivative activities with fifteen financial institutions, of which all but one are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. 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 (in thousands).

		December 31, 2014
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
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 Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–basis swaps	$	(755	)	$	755	$	−
		$	(755	)	$	755	$	−

		December 31, 2013
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	4,240	$	(1,218	)	$	3,022
	–collars		16,057		(7,671	)		8,386
	–basis swaps		7,686		(7,686	)		¾
Crude oil	–swaps		3,567		(1,321	)		2,246
NGLs	–C3 swaps		826		(826	)		¾
	–C4 swaps		863		(863	)		¾
	–C5 swaps		121		(121	)		¾
		$	33,360	$	(19,706	)	$	13,654

		December 31, 2013
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(4,790	)	$	1,218	$	(3,572	)
	–collars		(13,345	)		7,671		(5,674	)
	–basis swaps		(3,756	)		7,686		3,930
Crude oil	–swaps		(4,711	)		1,321		(3,390	)
	–collars		(398	)		¾		(398	)
NGLs	–C3 swaps		(18,172	)		826		(17,346	)
	–C4 swaps		(757	)		863		106
	–C5 swaps		¾			121		121
		$	(45,929	)	$	19,706	$	(26,223	)

The effects of our cash flow hedges (or those derivatives that qualified for hedge accounting) on AOCI in the accompanying consolidated balance sheets is summarized below (in thousands):

	Year Ended December 31,
	Change in Hedge Derivative Fair Value					Realized Gain Reclassified from OCI Into Revenue ^(a)
	2014		2013			2014			2013

Swaps	$	¾	$	125		$	4,544		$	15,171
Collars		¾		(7,015	)		5,678			105,272
Income taxes		¾		2,687			(3,986	)		(46,973	)
	$	¾	$	(4,203	)	$	6,236		$	73,470

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

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

	Year Ended December 31,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)									Gain (Loss) Recognized in Income (Ineffective Portion)								Derivative Fair Value Income (Loss)
	2014			2013			2012			2014		2013			2012			2014			2013			2012
Swaps	$	367,484		$	(48,492	)	$	11,601		$	¾	$	(2,034	)	$	(657	)	$	367,484		$	(50,526	)	$	10,944
Re-purchased swaps		¾			1,323			9,313			¾		¾			¾			¾			1,323			9,313
Collars		42,836			(15,166	)		5,126			¾		(896	)		1,782			42,836			(16,062	)		6,908
Call options		¾			¾			13,178			¾		¾			—			¾			¾			13,178
Put options		¾			¾			(30	)		¾		¾			—			¾			¾			(30	)
Basis swaps		(26,800	)		3,440			1,124			¾		¾			—			(26,800	)		3,440			1,124
Total	$	383,520		$	(58,895	)	$	40,312		$	¾	$	(2,930	)	$	1,125		$	383,520		$	(61,825	)	$	41,437

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Fair Value Measurements

12 Months Ended

Dec. 31, 2014

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, 2014 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2014
Trading securities held in the deferred compensation plans		$	68,454	$	¾	$	¾	$	68,454
Derivatives	–swaps		¾		344,216		¾		344,216
	–collars		¾		57,460		¾		57,460
	–basis swaps		¾		1,687		¾		1,687

		Fair Value Measurements at December 31, 2013 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2013
Trading securities held in the deferred compensation plans		$	67,776	$	—		$	—	$	67,766
Derivatives	–swaps		—		(18,813	)		—		(18,813	)
	–collars		—		2,314			—		2,314
	–basis swaps		—		3,382			548		3,930

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2014 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. As of December 31, 2013, we had four natural gas basis swaps categorized as Level 3 due to the forward price curve being unavailable for the regional sales point. As of December 31, 2014, we have no natural gas basis swaps categorized as Level 3. The following is a reconciliation of the net beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

	2014
Beginning balance	$	548
Changes in fair value of derivative instruments		2,979
Settlements received		(3,527	)
Ending balance	$	—

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 income. 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. For the year ended December 31, 2012, interest and dividends were $1.4 million and mark-to-market was a gain of $4.7 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 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. We recorded non-cash charges during the year ended 2012 of $31.1 million related to our Mississippi natural gas and oil properties and $3.2 million related to our remaining oil and natural gas properties in North Texas. Also in 2013 and 2012, 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 and $1.3 million in 2012. 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,
	2014				2013				2012
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	15,605	$	28,024	$	500	$	7,012	$	12,604	$	34,273
Surface property		¾		¾		5,550		741		6,269		1,281

Fair Values - Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2014 and 2013 (in thousands):

	December 31, 2014						December 31, 2013
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and basis swaps	$	403,363		$	403,363		$	13,654		$	13,654
Marketable securities^(a)		68,454			68,454			67,766			67,766
Liabilities:
Commodity swaps, collars and basis swaps		¾			¾			(26,223	)		(26,223	)
Bank credit facility^(b)		(723,000	)		(723,000	)		(500,000	)		(500,000	)
Deferred compensation plan^(c)		(203,433	)		(203,433	)		(271,738	)		(271,738	)
8.00% senior subordinated notes due 2019^(b)		¾			¾			(290,516	)		(319,500	)
6.75% senior subordinated notes due 2020^(b)		(500,000	)		(523,125	)		(500,000	)		(541,250	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(520,000	)		(500,000	)		(530,625	)
5.00% senior subordinated notes due 2022^(b)		(600,000	)		(601,500	)		(600,000	)		(588,750	)
5.00% senior subordinated notes due 2023^(b)		(750,000	)		(754,688	)		(750,000	)		(732,188	)

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

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes, which are Level 2 inputs.

^(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.

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

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2014

Stock-Based Compensation Plans

(12)	STOCK-BASED COMPENSATION PLANS

Description of the Plans

The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the Compensation Committee of the Board of Directors to grant, among other things, stock options, stock appreciation rights (“SARs”), performance share unit awards (“PSUs”) and restricted stock awards to employees and directors. The 2004 Non-Employee Director Stock Option Plan (the “Director Plan”) allows such grants to our non-employee directors of our Board of Directors. The 2005 Plan was approved by stockholders in May 2005 and replaced our 1999 Stock Option Plan. Since then, no new grants have been made from the 1999 Stock Option Plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares plus (ii) the number of shares subject to 1999 Stock Option Plan awards outstanding at May 18, 2005 that subsequently lapse or terminate without the underlying shares being issued plus (iii) subsequent shares approved by the shareholders. The Director Plan, which expired at the end of 2014, was approved by stockholders in May 2004 with no more than 450,000 shares of common stock to be issued under the Director Plan.

Stock-Based Awards

Stock options represent the right to purchase shares of stock in the future at the fair value of the stock on the date of grant. Most stock options granted under our stock option plans vest over a three-year period and expire five years from the date they were granted. 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 under the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted. Beginning in first quarter 2011, the Compensation Committee of our Board of Directors began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. In first quarter 2014, the Compensation Committee began granting PSU awards under our 2005 Plan. 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 three years. 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 income. 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 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 (in thousands):

	2014		2013		2012
Operating expense	$	4,208	$	2,755	$	2,415
Brokered natural gas and marketing expense		3,523		1,852		1,765
Exploration expense		4,569		4,025		4,049
General and administrative expense		55,382		55,737		44,541
Termination costs		2,999		¾		¾
Total	$	70,681	$	64,369	$	52,770

Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. The increase in the year ended 2013 stock-based compensation from 2012 is primarily due to additional expense of $10.0 million related to the acceleration of stock-based compensation for our former executive chairman who became a non-employee director on January 1, 2014. Stock-based compensation 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. As part of the closure of our Oklahoma City office announced in first quarter 2015, unvested SARs, restricted stock and PSUs will be modified and fully vested effective with the closing of the office. These costs were estimated at December 31, 2014 as probable to occur and $3.0 million was accrued within termination costs in the consolidated statements of income. For the year 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.

Stock Appreciation Right Awards

We have two active equity-based stock plans, the 2005 Plan and the Director Plan. Under these plans, incentive and non-qualified stock options, stock appreciation rights, restricted stock units and various other awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors. After December 31, 2014, no new grants will be issued from the Director Plan. All awards granted under these plans have been issued at prevailing market prices at the time of the grant. Of the 2.0 million grants outstanding at December 31, 2014, all grants relate to SARs. Information with respect to SARs activities is summarized below:

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2011		4,558,609		$	41.47
Granted		754,471			64.14
Exercised		(1,860,367	)		30.20
Expired/forfeited		(19,351	)		48.00
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

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2014:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$ 31.13–$ 39.99		3,260		0.58	$	38.82		3,260	$	38.82
40.00–49.99		542,206		0.49		46.47		542,206		46.47
50.00–59.99		355,856		1.38		52.35		355,856		52.35
60.00–69.99		614,909		2.33		64.18		422,546		64.21
70.00–79.99		448,418		3.30		75.88		196,064		76.30
80.00–81.15		1,900		3.69		81.15		1,900		81.15
Total		1,966,549		1.87	$	59.80		1,521,832	$	56.64

During 2014, we granted SARs to our former executive chairman in conjunction with his retirement from Range as an employee. During 2013 and 2012, we granted SARs to officers, non-officer employees and directors. The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:

	2014			2013			2012
Weighted average exercise price per share	$	81.74		$	75.82		$	64.14
Expected annual dividend yield		0.20	%		0.21	%		0.25	%
Expected life in years		4.3			3.7			3.7
Expected volatility		33	%		35	%		45	%
Risk-free interest rate		1.4	%		0.6	%		0.5	%
Weighted average grant date fair value per share	$	23.17		$	20.20		$	21.32

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 years ended December 31, 2014 was $27.1 million compared to $30.3 million in 2013 and $61.0 million in 2012. As of December 31, 2014, the aggregate intrinsic value of the awards outstanding was $4.2 million. The aggregate intrinsic value and weighted average remaining contractual life of SARs awards exercisable as of December 31, 2014 was $4.2 million and 1.6 years. As of December 31, 2014, the number of fully vested awards and awards expected to vest was 2.0 million shares. The weighted average exercise price and weighted average remaining contractual life of these awards were $59.72 and 1.9 years and the aggregate intrinsic value was $4.2 million. As of December 31, 2014, unrecognized compensation cost related to the awards was $3.9 million, which is expected to be recognized over a weighted average period of 1.1 years.

Performance Share Unit Awards

The following is a summary of our non-vested PSU awards outstanding at December 31, 2014:

	Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013		—		$	—
Granted ^(a)		227,929			86.14
Vested ^(b)		(92,077	)		86.23
Forfeited		(1,511	)		82.60
Outstanding at December 31, 2014		134,341		$	86.11

^(a⁾ Amounts granted 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.

^(b) Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

The following assumptions were used to estimate the fair value of PSUs granted during the year ended December 31, 2014:

	Year Ended December, 31, 2014
Risk-free interest rate		0.77	%
Expected annual volatility		33	%
Grant date fair value per unit	$	86.14

We recorded PSU compensation expense of $7.7 million in the year ended December 31, 2014 compared to none in the same period of 2013. As of December 31, 2014, there was $10.5 million of unrecognized compensation related to PSU awards to be recognized over a weighted average period of 2.3 years.

Restricted Stock Awards

Equity Awards

In 2014, we granted 356,000 restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded compensation expense for these awards of $26.3 million in the year ended December 31, 2014. In 2013, we granted 402,000 restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded compensation expense for these awards of $19.7 million in the year ended December 31, 2013. In 2012, we granted 364,000 restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded compensation expense for these awards of $11.8 million in the year ended December 31, 2012. As of December 31, 2014, there was $26.9 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.8 years. Restricted stock Equity Awards are not issued to employees until such time they are vested and the employees do not have the option to receive cash.

Liability Awards

In 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. In 2012, we granted 381,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $64.06. This grant included 14,700 issued to non-employee directors, which vest immediately, and 366,300 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $25.2 million in the year ended December 31, 2014 compared to $27.4 million in 2013 and $21.5 million in 2012. As of December 31, 2014, there was $22.0 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.8 years. Substantially 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 income (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan was $16.0 million in 2014. A summary of the status of our non-vested restricted stock outstanding at December 31, 2014 is summarized below:

	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2011		221,609		$	49.64		487,244		$	48.76
Granted		364,082			63.44		380,808			64.06
Vested		(208,802	)		56.73		(438,283	)		52.17
Forfeited		(27,733	)		58.65		(6,291	)		54.54
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

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. Beginning in 2008, we began matching up to 6% of salary in cash. Prior to 2013, all contributions became fully vested after the individual employee had two years of service with us. Beginning in 2013, vesting of our contributions is immediate. In 2014, we contributed $5.8 million to the 401(k) Plan compared to $5.1 million in 2013. 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 income. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market income of $74.6 million in 2014 compared to $55.3 million expense in 2013 and $7.2 million expense in 2012. The Rabbi Trust held 2.8 million shares (2.5 million of vested shares) of Range stock at December 31, 2014 compared to 2.8 million shares (2.4 million of vested shares) at December 31, 2013.

Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

(13)	SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(156	)	$	(347	)	$	386
Interest paid		165,530			159,137			153,249
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	56,822		$	76,373		$	57,982
Increase (decrease) in accrued capital expenditures		150,604			27,079			(94,121	)

Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

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 quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

Lease Commitments

We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases and amounts related to discontinued operations) totaled $13.3 million in 2014 compared to $13.1 million in 2013 and $13.8 million in 2012. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands):

	Operating Lease Obligations
2015	$	16,557
2016		12,700
2017		7,292
2018		5,660
2019		4,399
Thereafter		12,830
	$	59,438

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, 2014, future minimum transportation and gathering fees under our commitments are as follows (in thousands):

	Transportation and Gathering Contracts ^(a)
2015	$	342,204
2016		366,836
2017		356,789
2018		321,385
2019		317,627
Thereafter		1,842,410
	$	3,547,251

^(a) 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.

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 five and twenty year terms and are expected to begin mid-2015 through 2017. Based on these contracts, we will have additional transportation and gathering obligations for natural gas volumes from 7,000 mcfe per day to 400,000 mcfe per day, ethane volumes of 20,000 bbls per day and propane volumes of 20,000 bbls per day through the end of the contract terms.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Midcontinent and Marcellus Shale 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, 2014, our delivery commitments through 2028 were as follows:

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane (bbls per day)
2015		313,180	15,000
2016		268,055	15,000
2017		139,840	15,000
2018		30,000	15,000
2019		30,000	15,000
2020		30,000	15,000
2021		30,000	15,000
2022¾2028		—	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 10,000 bbls per day starting in 2015, increasing to 20,000 bbls per day in late 2015, increasing to 30,000 bbls per day in 2017 and 45,000 bbls per day in 2018 through the end of the term.

Other

We have agreements in place for hydraulic fracturing including related equipment, material and labor for $12.0 million in 2015. 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

12 Months Ended

Dec. 31, 2014

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 16, 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. In the past three years, there were no additional contributions made to fund the expansion of the Nora Field gathering system infrastructure.

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 income for 2014, 2013 and 2012. In 2014, we received partnership distributions of $7.0 million compared to $9.0 million in 2013 and $12.8 million in 2012. 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 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. For the year ended December 31, 2012, our equity in the losses of NGLLC of $1.2 million reflects a reduction of $7.5 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 have consolidated these operations into our consolidated financial statements.

Office Closing and Exit Costs

12 Months Ended

Dec. 31, 2014

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 lower commodity prices. The properties will be operated from our office in Fort Worth. As part of an ongoing benefit arrangement that was probable of occurring as of the end of the year, 2014 includes $8.4 million of accrued severance and accelerated vesting of SARs, restricted stock and PSUs. Additional costs, including office rent and other employee-related termination costs, related to the closing of this office will be accrued during 2015 as required by GAAP. The following table details the accrued liability as of December 31, 2014 (in thousands):

	2014
Beginning balance	$	—
Accrued termination costs		8,371
Ending balance	$	8,371

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2014

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. Second quarter 2014 includes a gain of $280.1 million from the Conger Exchange. General and administrative expense in first quarter 2013 includes a $35.0 million Drummond lawsuit settlement accrual. Second quarter 2013 includes an additional $52.5 million related to the Drummond legal settlement. Second quarter 2013 also includes a gain of $79.4 million from the sale of our Delaware and Permian basin properties in southeast New Mexico and West Texas. The fourth quarter 2013 deferred tax expense includes a $21.2 million benefit for state apportionment rate adjustments (in thousands, except per share data):

	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
(Loss) gain on the sale of assets		(353	)		282,064			167			3,760			285,638
Brokered natural gas, marketing and other		32,528			30,052			28,324			39,644			130,548
Total revenue and other income		457,342			765,524			616,615			872,214			2,711,695
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 expense		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
Total costs and expenses		405,864			476,159			376,675			422,112			1,680,810
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

	2013
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	398,239		$	437,678		$	431,214		$	448,545		$	1,715,676
Derivative fair value (loss) income		(99,875	)		137,760			(40,355	)		(59,355	)		(61,825	)
(Loss) gain on the sale of assets		(166	)		83,287			6,008			3,162			92,291
Brokered natural gas, marketing and other		21,041			14,631			45,171			35,734			116,577
Total revenue and other income		319,239			673,356			442,038			428,086			1,862,719
Costs and expenses:
Direct operating		30,188			32,636			30,907			34,360			128,091
Transportation, gathering and compression		62,416			66,048			60,958			66,820			256,242
Production and ad valorem taxes		11,383			11,113			11,454			11,290			45,240
Brokered natural gas and marketing		22,315			16,662			51,117			41,692			131,786
Exploration		16,780			13,068			20,496			14,065			64,409
Abandonment and impairment of unproved properties		15,218			19,156			11,692			5,852			51,918
General and administrative		84,058			101,987			44,919			60,207			291,171
Deferred compensation plan		42,360			(6,878	)		(2,225	)		22,039			55,296
Interest expense		42,210			45,071			44,321			44,955			176,557
Loss on early extinguishment of debt		¾			12,280			¾			¾			12,280
Depletion, depreciation and amortization		115,101			119,995			130,343			126,958			492,397
Impairment of proved properties and other		¾			741			7,012			¾			7,753
Total costs and expenses		442,029			431,879			410,994			428,238			1,713,140
(Loss) income before income taxes		(122,790	)		241,477			31,044			(152	)		149,579
Income tax (benefit) expense:
Current		25			(25	)		¾			(143	)		(143	)
Deferred		(47,205	)		97,519			11,866			(28,180	)		34,000
		(47,180	)		97,494			11,866			(28,323	)		33,857
Net (loss) income	$	(75,610	)	$	143,983		$	19,178		$	28,171		$	115,722
Net (loss) income per common share:
Basic	$	(0.47	)	$	0.88		$	0.12		$	0.17		$	0.71
Diluted	$	(0.47	)	$	0.88		$	0.12		$	0.17		$	0.70

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

12 Months Ended

Dec. 31, 2014

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,
	2014			2013			2012
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	9,624,725		$	8,225,859		$	7,368,308
Unproved properties		943,246			807,022			743,467
Total		10,567,971			9,032,881			8,111,775
Accumulated depreciation, depletion and amortization		(2,590,398	)		(2,274,444	)		(2,015,591	)
Net capitalized costs	$	7,977,573		$	6,758,437		$	6,096,184

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

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

	December 31,
	2014		2013		2012
	(in thousands)
Acquisitions ^(b)	$	404,252	$	¾	$	¾
Acreage purchases		226,475		137,538		188,843
Development		1,119,896		938,668		1,049,129
Exploration:
Drilling		180,925		189,742		309,816
Expense		58,979		60,384		65,758
Stock-based compensation expense		4,569		4,025		4,049
Gas gathering facilities:
Development		13,137		47,086		41,035
Subtotal		2,008,233		1,377,443		1,658,630
Asset retirement obligations		56,822		76,373		57,982
Total costs incurred	$	2,065,055	$	1,453,816	$	1,716,612

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

^(b)	See also Note 3 for additional information related to the 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.

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 2014, the following independent petroleum consultants conducted an audit of our reserves: DeGolyer and MacNaughton (Midcontinent) and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2014, these consultants collectively audited approximately 96% of our proved reserves. Copies of the summary reserve reports prepared by each of these independent petroleum consultants are included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein 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 each of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any 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 pre-tax 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 than those of the auditors and some may be less than the estimates of the reserve auditors. When such differences do not exceed 10% in the aggregate, our reserve auditors are satisfied that the proved reserves and pre-tax 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, 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. The average realized prices used at December 31, 2012 to estimate reserve information were $86.91 per barrel of oil, $32.23 per barrel of NGLs and $2.75 per mcf for gas, using a benchmark (NYMEX) of $95.05 per barrel and $2.76 per MMbtu.


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) ^(a)
Proved developed and undeveloped reserves:
Balance, December 31, 2011		4,009,676			142,515			31,532			5,053,961
Revisions		76,925			3,036			2,316			109,036
Extensions, discoveries and additions		996,059			113,392			15,131			1,767,202
Purchases		—			—			—			—
Property sales		(73,429	)		(11,575	)		(1,046	)		(149,153	)
Production		(216,555	)		(6,969	)		(2,851	)		(275,476	)
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
Proved developed reserves:
December 31, 2012		2,373,604			154,984			25,667			3,457,502
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
Proved undeveloped reserves:
December 31, 2012		2,419,072			85,415			19,415			3,048,068
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

^(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 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 net 91 Bcfe includes positive performance revisions, improved recovery 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 net 449 Bcfe includes positive performance revisions and improved recovery 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.

During 2012, we added approximately 1.8 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 56% of the 2012 reserve additions were attributable to natural gas. Also included in 2012 additions is 307 Bcfe of ethane reserves (51.2 Mmbbls) in the Marcellus Shale which was associated with initial ethane deliveries under contracts commencing in 2013. Revisions of previous estimates of a net 109 Bcfe include positive performance revisions primarily from our Marcellus Shale natural gas properties, partially offset by negative pricing revisions.

The following details the changes in proved undeveloped reserves for 2014 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2013	4,009,608
Undeveloped reserves transferred to developed	(620,167	)
Revisions^(a)	(147,019	)
Purchases/ (sales)	(58,045	)
Extension and discoveries	1,776,091
Ending proved undeveloped reserves at December 31, 2014	4,960,468

^(a) Includes 611,341 Mmcfe of proved undeveloped reserves dropped due to the five year rule.

Approximately $591.0 million was spent during 2014 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $981.1 million in 2015, $1.0 billion in 2016 and $993.5 million in 2017. Included in proved undeveloped reserves at December 31, 2014 are approximately 3 bcfe of reserves (less than 1% of total proved undeveloped reserves) that have been reported for five or more years. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2019.

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 2014, 2013 and 2012, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

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

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,
	2014			2013
	(in thousands)
Future cash inflows	$	46,507,646		$	35,143,097
Future costs:
Production		(15,239,210	)		(10,176,140	)
Development^(a)		(4,275,693	)		(3,938,296	)
Future net cash flows before income taxes		26,992,743			21,028,661
Future income tax expense		(8,900,383	)		(6,913,196	)
Total future net cash flows before 10% discount		18,092,360			14,115,465
10% annual discount		(10,499,333	)		(8,253,234	)
Standardized measure of discounted future net cash flows	$	7,593,027		$	5,862,231

^(a) 2014 includes $439.6 million of undiscounted future asset retirement costs estimated as of December 31, 2014, using current estimates of future abandonment costs.

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

	December 31,
	2014			2013			2012
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	5,069		$	2,172,704		$	(2,498,616	)
Revisions in quantities		102,760			513,168			88,190
Changes in future development and abandonment costs		(407,688	)		(275,468	)		(354,766	)
Net change in income taxes		(441,935	)		(1,299,227	)		832,830
Accretion of discount		789,754			395,989			608,381
Purchases of reserves in place		297,358			¾			—
Additions to proved reserves from extensions, discoveries and improved recovery		2,713,999			1,981,054			1,429,340
Natural gas, NGLs and oil sales, net of production costs		(1,391,663	)		(1,286,103	)		(976,224	)
Development costs incurred during the period		755,384			462,862			562,329
Sales of reserves in place		(249,055	)		(162,463	)		(120,637	)
Timing and other		(443,187	)		135,910			(861,919	)
Net change for the year		1,730,796			2,638,426			(1,291,092	)
Beginning of year		5,862,231			3,223,805			4,514,897
End of year	$	7,593,027		$	5,862,231		$	3,223,805

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

Use of Estimates

Business Segment Information

Revenue Recognition, Accounts Receivable and Gas Imbalances

Cash and Cash Equivalents

Marketable Securities

Inventory

Natural Gas and Oil Properties

Property Acquisition Costs

Depreciation, Depletion and Amortization

Impairments

Dispositions

Acquisitions

Other Property and Equipment

Other Assets

Stock-based Compensation Arrangements

Derivative Financial Instruments and Hedging

Concentrations of Credit Risk

Asset Retirement Obligations

Environmental Costs

Deferred Taxes

Accumulated Other Comprehensive Income

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2011	$	254,678		$	(98,051	)	$	156,627
Contract settlements reclassified to income		(236,305	)		91,871			(144,434	)
Change in unrealized deferred hedging gains		119,182			(47,466	)		71,716
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 losses		(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

Accounting Pronouncements Implemented

Recently Adopted

Accounting Pronouncements Not Yet Adopted

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Accumulated Other Comprehensive Income

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2011	$	254,678		$	(98,051	)	$	156,627
Contract settlements reclassified to income		(236,305	)		91,871			(144,434	)
Change in unrealized deferred hedging gains		119,182			(47,466	)		71,716
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 losses		(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

Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Summary of Fair Value of Assets Acquired and Liabilities Assumed in Transaction

The following table presents the fair value of assets acquired and liabilities assumed in the transaction (in thousands):


	Conger Exchange
Consideration
Fair value of net assets transferred	$	550,273

Fair value of assets acquired and liabilities assumed
Cash	$	151,675
Working capital – Nora Gathering, LLC		12,731
Natural gas and oil properties		402,176
Transportation and field assets		7,793
Other liabilities-firm transportation contract		(12,175	)
Asset retirement obligations		(11,927	)
Fair value of net assets acquired and liabilities assumed	$	550,273

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax


	Year Ended December 31,
	2014		2013			2012
Federal statutory tax rate	35.0	%		35.0	%		35.0	%
State	3.1			(2.3	)		0.7
State apportionment rate change	(0.2	)		(14.9	)		¾
Non-deductible executive compensation	0.2			0.7			1.4
Valuation allowances	0.2			3.5			8.8
Other	0.2			0.6			2.2
Consolidated effective tax rate	38.5	%		22.6	%		48.1	%

Income Tax Expense (Benefit) Attributable to Income Before Income Taxes

Income tax expense (benefit) attributable to income before income taxes consists of the following (in thousands):

		2014						2013									2012
		Current	Deferred		Total		Current			Deferred			Total			Current			Deferred		Total
U.S. federal	$	¾	$	361,152	$	361,152	$	¾		$	58,527		$	58,527		$	—		$	11,873	$	11,873
U.S. state and local		1		35,350		35,351		(143	)		(24,527	)		(24,670	)		(1,778	)		1,959		181
Total	$	1	$	396,502	$	396,503	$	(143	)	$	34,000		$	33,857		$	(1,778	)	$	13,832	$	12,054

Significant Components of Deferred Tax Assets and Liabilities

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

	December 31,
	2014			2013
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	9,286		$	9,128
Current portion of asset retirement obligation		5,745			1,854
Cumulative mark-to-market loss		584			15,193
Net operating loss carryforward		—			23,079
Other		9,921			7,936
Total current		25,536			57,190
Non-current
Net operating loss carryforward		176,812			57,266
Deferred compensation		64,656			91,094
Equity compensation		25,833			22,800
AMT credits and other credits		4,447			4,122
Non-current portion of asset retirement obligation		104,063			86,126
Cumulative mark-to-market loss		65			¾
Other		987			1,116
Valuation allowance		(16,599	)		(14,781	)
Total non-current		360,264			247,743
Deferred tax liabilities:
Current
Net gain in AOCI related to hedge derivatives		—			(3,987	)
Other		(2,350	)		(1,789	)
Cumulative mark-to-market gain		(138,773	)		¾
Total current		(141,123	)		(5,776	)
Non-current
Depreciation, depletion and investments		(1,342,039	)		(1,010,757	)
Cumulative mark-to-market gain		(15,410	)		(6,424	)
Other		(310	)		(2,542	)
Total non-current		(1,357,759	)		(1,019,723	)
Net deferred tax liability	$	(1,113,082	)	$	(720,566	)

Net Income Per Common Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Computations of Basic and Diluted (Loss) Income Per Common Share


	Year Ended December 31,
	2014			2013			2012
Net income, as reported	$	634,382		$	115,722		$	13,002
Participating basic earnings ^(a)		(10,725	)		(1,975	)		(460	)
Basic net income attributed to common shareholders		623,657			113,747			12,542
Reallocation of participating earnings ^(a)		48			9			—
Diluted net income attributed to common shareholders	$	623,705		$	113,756		$	12,542
Net income per common share:
Basic	$	3.81		$	0.71		$	0.08
Diluted	$	3.79		$	0.70		$	0.08

^(a)

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,
	2014	2013		2012
Denominator:
Weighted average common shares outstanding – basic	163,625		160,438		159,431
Effect of dilutive securities:
Director and employee SARs and restricted stock Equity Awards	778		969		876
Weighted average common shares outstanding – diluted	164,403		161,407		160,307

Suspended Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2014

Suspended Exploratory Well Costs

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2014, 2013 and 2012 (in thousands, except for number of projects):

	2014			2013			2012
Balance at beginning of period	$	6,964		$	57,360		$	93,388
Additions to capitalized exploratory well costs pending the determination of proved reserves		18,747			39,832			153,250
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(15,735	)		(84,840	)		(184,298	)
Divested wells		¾			¾			(4,980	)
Capitalized exploratory well costs charged to expense		(6,980	)		(5,388	)		—
Balance at end of period		2,996			6,964			57,360
Less exploratory well costs that have been capitalized for a period of one year or less		(2,996	)		¾			(45,965	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	¾		$	6,964		$	11,395
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		¾			1			5

Indebtedness (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt Outstanding

	December 31,
	2014		2013
Bank debt (2.0%)	$	723,000	$	500,000
Senior subordinated notes:
8.00% senior subordinated notes due 2019, net of $9,484 discount		¾		290,516
6.75% senior subordinated notes due 2020		500,000		500,000
5.75% senior subordinated notes due 2021		500,000		500,000
5.00% senior subordinated notes due 2022		600,000		600,000
5.00% senior subordinated notes due 2023		750,000		750,000
Total debt	$	3,073,000	$	3,140,516

Schedule for Long-Term Debt Outstanding

The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2014 (in thousands):

	Year Ended December 31,
2015	$	—
2016		—
2017		—
2018		—
2019		723,000
Thereafter		2,350,000
	$	3,073,000

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

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

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

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

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

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2014

Asset Retirement Obligation


	2014			2013
Beginning of period	$	230,077		$	146,478
Liabilities incurred		8,602			8,731
Acquisitions		11,927			¾
Liability released		(8,309	)		¾
Liabilities settled		(4,442	)		(424	)
Disposition of wells		(13,951	)		(3,129	)
Accretion expense		15,226			10,778
Change in estimate		48,333			67,643
End of period		287,463			230,077
Less current portion		(15,067	)		(5,037	)
Long-term asset retirement obligations	$	272,396		$	225,040

Capital Stock (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Capital Stock


	Year Ended December 31,
	2014		2013		2012
Beginning balance		163,342,894		162,514,098		161,131,547
Equity offering		4,560,000		−		−
Stock options/SARs exercised		195,242		278,916		926,425
Restricted stock grants		270,062		401,122		354,674
Restricted stock units vested		244,413		119,480		57,824
Treasury shares		15,566		29,278		43,628
Ending balance		168,628,177		163,342,894		162,514,098

Derivative Activities (Tables)

12 Months Ended

Dec. 31, 2014

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, 2014:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2015	Collars	145,000 Mmbtu/day	$4.07–$4.56
2015	Swaps	412,390 Mmbtu/day	$4.15
2016	Swaps	120,000 Mmbtu/day	$4.15
Crude Oil
2015	Swaps	9,626 bbls/day	$90.57
2016	Swaps	1,000 bbls/day	$91.43
NGLs (C3 - Propane)
2015	Swaps	2,245 bbls/day	$0.95/gallon

NGLs (C5 - Natural Gasoline)
2015-First Quarter		Swaps		500 bbls/day		$2.14/gallon

Combined Fair Value of Derivatives, by Consolidated Balance Sheets

		December 31, 2014
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
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 Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–basis swaps	$	(755	)	$	755	$	−
		$	(755	)	$	755	$	−

		December 31, 2013
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	4,240	$	(1,218	)	$	3,022
	–collars		16,057		(7,671	)		8,386
	–basis swaps		7,686		(7,686	)		¾
Crude oil	–swaps		3,567		(1,321	)		2,246
NGLs	–C3 swaps		826		(826	)		¾
	–C4 swaps		863		(863	)		¾
	–C5 swaps		121		(121	)		¾
		$	33,360	$	(19,706	)	$	13,654

		December 31, 2013
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative (liabilities):
Natural gas	–swaps	$	(4,790	)	$	1,218	$	(3,572	)
	–collars		(13,345	)		7,671		(5,674	)
	–basis swaps		(3,756	)		7,686		3,930
Crude oil	–swaps		(4,711	)		1,321		(3,390	)
	–collars		(398	)		¾		(398	)
NGLs	–C3 swaps		(18,172	)		826		(17,346	)
	–C4 swaps		(757	)		863		106
	–C5 swaps		¾			121		121
		$	(45,929	)	$	19,706	$	(26,223	)

Effects of Cash Flow Hedges and Other Hedges on Accumulated Other Comprehensive Income

The effects of our cash flow hedges (or those derivatives that qualified for hedge accounting) on AOCI in the accompanying consolidated balance sheets is summarized below (in thousands):

	Year Ended December 31,
	Change in Hedge Derivative Fair Value					Realized Gain Reclassified from OCI Into Revenue ^(a)
	2014		2013			2014			2013

Swaps	$	¾	$	125		$	4,544		$	15,171
Collars		¾		(7,015	)		5,678			105,272
Income taxes		¾		2,687			(3,986	)		(46,973	)
	$	¾	$	(4,203	)	$	6,236		$	73,470

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

Effects of Non-Hedge Derivatives on Consolidated Statements of Operations

	Year Ended December 31,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)									Gain (Loss) Recognized in Income (Ineffective Portion)								Derivative Fair Value Income (Loss)
	2014			2013			2012			2014		2013			2012			2014			2013			2012
Swaps	$	367,484		$	(48,492	)	$	11,601		$	¾	$	(2,034	)	$	(657	)	$	367,484		$	(50,526	)	$	10,944
Re-purchased swaps		¾			1,323			9,313			¾		¾			¾			¾			1,323			9,313
Collars		42,836			(15,166	)		5,126			¾		(896	)		1,782			42,836			(16,062	)		6,908
Call options		¾			¾			13,178			¾		¾			—			¾			¾			13,178
Put options		¾			¾			(30	)		¾		¾			—			¾			¾			(30	)
Basis swaps		(26,800	)		3,440			1,124			¾		¾			—			(26,800	)		3,440			1,124
Total	$	383,520		$	(58,895	)	$	40,312		$	¾	$	(2,930	)	$	1,125		$	383,520		$	(61,825	)	$	41,437

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=35706170&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=35706170&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

		Fair Value Measurements at December 31, 2014 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2014
Trading securities held in the deferred compensation plans		$	68,454	$	¾	$	¾	$	68,454
Derivatives	–swaps		¾		344,216		¾		344,216
	–collars		¾		57,460		¾		57,460
	–basis swaps		¾		1,687		¾		1,687

		Fair Value Measurements at December 31, 2013 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2013
Trading securities held in the deferred compensation plans		$	67,776	$	—		$	—	$	67,766
Derivatives	–swaps		—		(18,813	)		—		(18,813	)
	–collars		—		2,314			—		2,314
	–basis swaps		—		3,382			548		3,930

Reconciliation of the Net Beginning and Ending Balances for Derivative Instruments

The following is a reconciliation of the net beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

	2014
Beginning balance	$	548
Changes in fair value of derivative instruments		2,979
Settlements received		(3,527	)
Ending balance	$	—

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,
	2014				2013				2012
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties	$	15,605	$	28,024	$	500	$	7,012	$	12,604	$	34,273
Surface property		¾		¾		5,550		741		6,269		1,281

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, 2014 and 2013 (in thousands):

	December 31, 2014						December 31, 2013
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars and basis swaps	$	403,363		$	403,363		$	13,654		$	13,654
Marketable securities^(a)		68,454			68,454			67,766			67,766
Liabilities:
Commodity swaps, collars and basis swaps		¾			¾			(26,223	)		(26,223	)
Bank credit facility^(b)		(723,000	)		(723,000	)		(500,000	)		(500,000	)
Deferred compensation plan^(c)		(203,433	)		(203,433	)		(271,738	)		(271,738	)
8.00% senior subordinated notes due 2019^(b)		¾			¾			(290,516	)		(319,500	)
6.75% senior subordinated notes due 2020^(b)		(500,000	)		(523,125	)		(500,000	)		(541,250	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(520,000	)		(500,000	)		(530,625	)
5.00% senior subordinated notes due 2022^(b)		(600,000	)		(601,500	)		(600,000	)		(588,750	)
5.00% senior subordinated notes due 2023^(b)		(750,000	)		(754,688	)		(750,000	)		(732,188	)

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

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes, which are Level 2 inputs.

^(c)	The fair value of our deferred compensation plan is updated based on closing prices on the balance sheet date.

Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2014

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 (in thousands):

	2014		2013		2012
Operating expense	$	4,208	$	2,755	$	2,415
Brokered natural gas and marketing expense		3,523		1,852		1,765
Exploration expense		4,569		4,025		4,049
General and administrative expense		55,382		55,737		44,541
Termination costs		2,999		¾		¾
Total	$	70,681	$	64,369	$	52,770

Stock Option and SARs Activities

Information with respect to SARs activities is summarized below:

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2011		4,558,609		$	41.47
Granted		754,471			64.14
Exercised		(1,860,367	)		30.20
Expired/forfeited		(19,351	)		48.00
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

Outstanding SARs

The following table shows information with respect to SARs outstanding and exercisable at December 31, 2014:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$ 31.13–$ 39.99		3,260		0.58	$	38.82		3,260	$	38.82
40.00–49.99		542,206		0.49		46.47		542,206		46.47
50.00–59.99		355,856		1.38		52.35		355,856		52.35
60.00–69.99		614,909		2.33		64.18		422,546		64.21
70.00–79.99		448,418		3.30		75.88		196,064		76.30
80.00–81.15		1,900		3.69		81.15		1,900		81.15
Total		1,966,549		1.87	$	59.80		1,521,832	$	56.64

Weighted Average Grant Date Fair Value of SARs

	2014			2013			2012
Weighted average exercise price per share	$	81.74		$	75.82		$	64.14
Expected annual dividend yield		0.20	%		0.21	%		0.25	%
Expected life in years		4.3			3.7			3.7
Expected volatility		33	%		35	%		45	%
Risk-free interest rate		1.4	%		0.6	%		0.5	%
Weighted average grant date fair value per share	$	23.17		$	20.20		$	21.32

Summary of Performance Share Unit Awards Activity

The following is a summary of our non-vested PSU awards outstanding at December 31, 2014:

	Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013		—		$	—
Granted ^(a)		227,929			86.14
Vested ^(b)		(92,077	)		86.23
Forfeited		(1,511	)		82.60
Outstanding at December 31, 2014		134,341		$	86.11

^(b) Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

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, 2014:

	Year Ended December, 31, 2014
Risk-free interest rate		0.77	%
Expected annual volatility		33	%
Grant date fair value per unit	$	86.14

Restricted Stock and Restricted Stock Units Outstanding

A summary of the status of our non-vested restricted stock outstanding at December 31, 2014 is summarized below:

	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2011		221,609		$	49.64		487,244		$	48.76
Granted		364,082			63.44		380,808			64.06
Vested		(208,802	)		56.73		(438,283	)		52.17
Forfeited		(27,733	)		58.65		(6,291	)		54.54
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

Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Net cash provided from operating activities included:
Income taxes (refunded from) paid to taxing authorities	$	(156	)	$	(347	)	$	386
Interest paid		165,530			159,137			153,249
Non-cash investing and financing activities included:
Asset retirement costs capitalized, net	$	56,822		$	76,373		$	57,982
Increase (decrease) in accrued capital expenditures		150,604			27,079			(94,121	)

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2014

Commitments And Contingencies Disclosure [Abstract]

Future Minimum Rental Commitments

	Operating Lease Obligations
2015	$	16,557
2016		12,700
2017		7,292
2018		5,660
2019		4,399
Thereafter		12,830
	$	59,438

Schedule of Future Minimum Transportation and Gathering Fees

	Transportation and Gathering Contracts ^(a)
2015	$	342,204
2016		366,836
2017		356,789
2018		321,385
2019		317,627
Thereafter		1,842,410
	$	3,547,251

Future Delivery Commitments

Year Ending December 31,	Natural Gas (mmbtu per day)		Ethane (bbls per day)
2015		313,180	15,000
2016		268,055	15,000
2017		139,840	15,000
2018		30,000	15,000
2019		30,000	15,000
2020		30,000	15,000
2021		30,000	15,000
2022¾2028		—	15,000

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

Restructuring And Related Activities [Abstract]

Office Closing and Exit Costs (Tables)

12 Months Ended

Dec. 31, 2014

Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet

The following table details the accrued liability as of December 31, 2014 (in thousands):

	2014
Beginning balance	$	—
Accrued termination costs		8,371
Ending balance	$	8,371

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

	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
(Loss) gain on the sale of assets		(353	)		282,064			167			3,760			285,638
Brokered natural gas, marketing and other		32,528			30,052			28,324			39,644			130,548
Total revenue and other income		457,342			765,524			616,615			872,214			2,711,695
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 expense		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
Total costs and expenses		405,864			476,159			376,675			422,112			1,680,810
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

	2013
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	398,239		$	437,678		$	431,214		$	448,545		$	1,715,676
Derivative fair value (loss) income		(99,875	)		137,760			(40,355	)		(59,355	)		(61,825	)
(Loss) gain on the sale of assets		(166	)		83,287			6,008			3,162			92,291
Brokered natural gas, marketing and other		21,041			14,631			45,171			35,734			116,577
Total revenue and other income		319,239			673,356			442,038			428,086			1,862,719
Costs and expenses:
Direct operating		30,188			32,636			30,907			34,360			128,091
Transportation, gathering and compression		62,416			66,048			60,958			66,820			256,242
Production and ad valorem taxes		11,383			11,113			11,454			11,290			45,240
Brokered natural gas and marketing		22,315			16,662			51,117			41,692			131,786
Exploration		16,780			13,068			20,496			14,065			64,409
Abandonment and impairment of unproved properties		15,218			19,156			11,692			5,852			51,918
General and administrative		84,058			101,987			44,919			60,207			291,171
Deferred compensation plan		42,360			(6,878	)		(2,225	)		22,039			55,296
Interest expense		42,210			45,071			44,321			44,955			176,557
Loss on early extinguishment of debt		¾			12,280			¾			¾			12,280
Depletion, depreciation and amortization		115,101			119,995			130,343			126,958			492,397
Impairment of proved properties and other		¾			741			7,012			¾			7,753
Total costs and expenses		442,029			431,879			410,994			428,238			1,713,140
(Loss) income before income taxes		(122,790	)		241,477			31,044			(152	)		149,579
Income tax (benefit) expense:
Current		25			(25	)		¾			(143	)		(143	)
Deferred		(47,205	)		97,519			11,866			(28,180	)		34,000
		(47,180	)		97,494			11,866			(28,323	)		33,857
Net (loss) income	$	(75,610	)	$	143,983		$	19,178		$	28,171		$	115,722
Net (loss) income per common share:
Basic	$	(0.47	)	$	0.88		$	0.12		$	0.17		$	0.71
Diluted	$	(0.47	)	$	0.88		$	0.12		$	0.17		$	0.70

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

12 Months Ended

Dec. 31, 2014

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

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

	December 31,
	2014			2013			2012
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	9,624,725		$	8,225,859		$	7,368,308
Unproved properties		943,246			807,022			743,467
Total		10,567,971			9,032,881			8,111,775
Accumulated depreciation, depletion and amortization		(2,590,398	)		(2,274,444	)		(2,015,591	)
Net capitalized costs	$	7,977,573		$	6,758,437		$	6,096,184

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

Costs Incurred for Property Acquisition, Exploration and Development

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

	December 31,
	2014		2013		2012
	(in thousands)
Acquisitions ^(b)	$	404,252	$	¾	$	¾
Acreage purchases		226,475		137,538		188,843
Development		1,119,896		938,668		1,049,129
Exploration:
Drilling		180,925		189,742		309,816
Expense		58,979		60,384		65,758
Stock-based compensation expense		4,569		4,025		4,049
Gas gathering facilities:
Development		13,137		47,086		41,035
Subtotal		2,008,233		1,377,443		1,658,630
Asset retirement obligations		56,822		76,373		57,982
Total costs incurred	$	2,065,055	$	1,453,816	$	1,716,612

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

^(b)	See also Note 3 for additional information related to the 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.

Proved Developed and Undeveloped Reserves


	Natural Gas			NGLs			Crude Oil and Condensate			Natural Gas Equivalents
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe) ^(a)
Proved developed and undeveloped reserves:
Balance, December 31, 2011		4,009,676			142,515			31,532			5,053,961
Revisions		76,925			3,036			2,316			109,036
Extensions, discoveries and additions		996,059			113,392			15,131			1,767,202
Purchases		—			—			—			—
Property sales		(73,429	)		(11,575	)		(1,046	)		(149,153	)
Production		(216,555	)		(6,969	)		(2,851	)		(275,476	)
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
Proved developed reserves:
December 31, 2012		2,373,604			154,984			25,667			3,457,502
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
Proved undeveloped reserves:
December 31, 2012		2,419,072			85,415			19,415			3,048,068
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

^(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 for 2013 (Mmcfe)

The following details the changes in proved undeveloped reserves for 2014 (Mmcfe):

Beginning proved undeveloped reserves at December 31, 2013	4,009,608
Undeveloped reserves transferred to developed	(620,167	)
Revisions^(a)	(147,019	)
Purchases/ (sales)	(58,045	)
Extension and discoveries	1,776,091
Ending proved undeveloped reserves at December 31, 2014	4,960,468

^(a) Includes 611,341 Mmcfe of proved undeveloped reserves dropped due to the five year rule.

Standardized Measure of Discounted Future Net Cash Flows

	As of December 31,
	2014			2013
	(in thousands)
Future cash inflows	$	46,507,646		$	35,143,097
Future costs:
Production		(15,239,210	)		(10,176,140	)
Development^(a)		(4,275,693	)		(3,938,296	)
Future net cash flows before income taxes		26,992,743			21,028,661
Future income tax expense		(8,900,383	)		(6,913,196	)
Total future net cash flows before 10% discount		18,092,360			14,115,465
10% annual discount		(10,499,333	)		(8,253,234	)
Standardized measure of discounted future net cash flows	$	7,593,027		$	5,862,231

^(a) 2014 includes $439.6 million of undiscounted future asset retirement costs estimated as of December 31, 2014, using current estimates of future abandonment costs.

Changes in Discounted Future Net Cash Flows

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

	December 31,
	2014			2013			2012
	(in thousands)
Revisions of previous estimates:
Changes in prices and production costs	$	5,069		$	2,172,704		$	(2,498,616	)
Revisions in quantities		102,760			513,168			88,190
Changes in future development and abandonment costs		(407,688	)		(275,468	)		(354,766	)
Net change in income taxes		(441,935	)		(1,299,227	)		832,830
Accretion of discount		789,754			395,989			608,381
Purchases of reserves in place		297,358			¾			—
Additions to proved reserves from extensions, discoveries and improved recovery		2,713,999			1,981,054			1,429,340
Natural gas, NGLs and oil sales, net of production costs		(1,391,663	)		(1,286,103	)		(976,224	)
Development costs incurred during the period		755,384			462,862			562,329
Sales of reserves in place		(249,055	)		(162,463	)		(120,637	)
Timing and other		(443,187	)		135,910			(861,919	)
Net change for the year		1,730,796			2,638,426			(1,291,092	)
Beginning of year		5,862,231			3,223,805			4,514,897
End of year	$	7,593,027		$	5,862,231		$	3,223,805

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

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

Disclosure Summary Of Significant Accounting Policies Accumulated Other Comprehensive Income [Abstract]

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)		12 Months Ended
	Jun. 16, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Line Items]
Income (Loss) from equity method investments	$ 0	$ (3,095,000)	$ 2,973,000	$ (5,670,000)
Brokered margin gain (loss)		9,400,000	(5,700,000)
Allowance for doubtful accounts on accounts receivable		2,719,000	2,494,000
Bad debt expense		250,000	250,000	$ 750,000
Liability due to insufficient reserves		52,000
Inventory, other		17,854,000	12,451,000
Inventory, other		2,000,000	0
Materials and supplies inventory
Summary Of Significant Accounting Policies [Line Items]
Inventory, other		$ 11,800,000	$ 9,600,000

Summary of Significant Accounting Policies - Additional Information 1 (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Line Items]
Net book value of unproved properties	$ 943,200				$ 807,000				$ 943,200	$ 807,000
Abandonment and impairment of unproved properties	14,308	$ 13,444	$ 9,332	$ 9,995	5,852	$ 11,692	$ 19,156	$ 15,218	$ 47,079	51,918	$ 125,278
Useful life of assets									10 years
Depreciation expense									$ 12,900	13,200	$ 13,200
Unamortized debt issuance costs	42,200				44,500				42,200	44,500
Marketable securities	68,500				67,800				68,500	67,800
Other investments	$ 10,300				$ 9,000				$ 10,300	$ 9,000
Minimum \| Associated assets
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets									5 years
Minimum \| Other property and equipment
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets									3 years
Maximum \| Associated assets
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets									10 years
Maximum \| Other property and equipment
Summary Of Significant Accounting Policies [Line Items]
Useful life of assets									10 years

Summary of Significant Accounting Policies - Additional Information 2 (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) Customer Counterparty	Dec. 31, 2013 USD ($) Customer	Dec. 31, 2012 Customer
Summary Of Significant Accounting Policies [Line Items]
Allowance for uncollectible receivables \| $	$ 2.7	$ 2.5
Number of customers accounted more than 10% of total oil and gas revenues \| Customer	4	4	2
Net derivative asset \| $	$ 30.3
Number of counterparties \| Counterparty	1
Total Number of Derivative Counterparties \| Counterparty	15
Customer Concentration Risk \| Minimum \| Sales revenue
Summary Of Significant Accounting Policies [Line Items]
Minimum percentage of oil and gas sales revenue for identifying major customer	10.00%	10.00%	10.00%

Summary of Significant Accounting Policies - Accumulated Other Comprehensive Income (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Beginning Balance, Gross

$ 10,222

$ 137,555

$ 254,678

Contract settlements reclassified to income, Gross

(10,222)

(120,443)

(236,305)

Change in unrealized deferred hedging gains (losses), Gross

(6,890)

119,182

Ending Balance, Gross

10,222

137,555

Beginning Balance, Tax Effect

(3,986)

(53,646)

(98,051)

Contract settlements reclassified to income, Tax Effect

3,986

46,973

91,871

Change in unrealized deferred hedging (losses) gains, tax effect

2,687

(47,466)

Ending Balance, Tax Effect

(3,986)

(53,646)

Beginning Balance, Net of Tax

6,236

83,909

156,627

Contract settlements reclassified to income, Net of Tax

$ (6,236)

(73,470)

(144,434)

Change in unrealized deferred hedging (losses) gains, net of taxes

^[1]

(4,203)

71,716

Ending Balance, Net of Tax

$ 6,236

$ 83,909

[1]	Amounts are net of income tax benefit of $2,687 for the year ended December 31, 2013 compared to income tax expense of $47,466 for the year ended December 31, 2012.

Acquisitions and Dispositions - Additional Information (Detail) - USD ($) $ in Thousands		1 Months Ended				3 Months Ended								6 Months Ended	7 Months Ended	12 Months Ended
	Jun. 16, 2014	Jun. 30, 2014	Apr. 30, 2014	Apr. 30, 2013	Nov. 30, 2012	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Jun. 16, 2014	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Acquisitions And Disposals [Line Items]
(Loss) gain on the sale of assets						$ 3,760	$ 167	$ 282,064	$ (353)	$ 3,162	$ 6,008	$ 83,287	$ (166)			$ 285,638	$ 92,291	$ 49,132
Delaware and Permian Basin
Significant Acquisitions And Disposals [Line Items]
(Loss) gain on the sale of assets				$ 83,300
Selling expenses for property sale				4,200
Proceeds from sale of oil and gas				$ 275,000
Ardmore Woodford properties
Significant Acquisitions And Disposals [Line Items]
(Loss) gain on the sale of assets					$ 55,200
Proceeds from sale of oil and gas					$ 135,000
Miscellaneous Proved and Unproved Properties
Significant Acquisitions And Disposals [Line Items]
(Loss) gain on the sale of assets																$ 2,900	13,200	(6,100)
Nora Gathering, LLC
Significant Acquisitions And Disposals [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
Conger Exchange Transaction
Significant Acquisitions And Disposals [Line Items]
(Loss) gain on the sale of assets								$ 280,100
Selling expenses for property sale		$ 5,000
Net operating income prior to disposition														$ 21,900			$ 48,700	$ 40,200
Carrying amount of assets prior to exchange			$ 271,800
Recognized revenue from sale of property interests acquired															$ 33,800
Net operating income															25,700
(Loss) gain on the sale of assets prior to selling expenses		287,700
Conger Exchange Transaction \| EQT Corporation
Significant Acquisitions And Disposals [Line Items]
Cash proceeds from sale of assets			$ 145,000
Sale and exchange transaction, closing date																Jun. 16, 2014
(Loss) gain on the sale of assets	$ 272,700
Selling expenses for property sale	$ 5,000
Conger Exchange Transaction \| Nora Gathering, LLC
Significant Acquisitions And Disposals [Line Items]
Gain on sale of assets																$ 10,000
Trade receivables relating to acquisition						$ 5,500									$ 5,500	$ 5,500
Gain on the remeasurement of membership interest		$ 10,000

Acquisitions and Dispositions - Summary of Fair Value of Assets Acquired and Liabilities Assumed in Transaction (Detail) - EQT Corporation $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Fair value of net assets transferred	$ 550,273
Cash	151,675
Working capital – Nora Gathering, LLC	12,731
Natural gas and oil properties	402,176
Transportation and field assets	7,793
Other liabilities-firm transportation contract	(12,175)
Asset retirement obligations	(11,927)
Fair value of net assets acquired and liabilities assumed	$ 550,273

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Income tax expense	$ 166,048,000	$ 93,522,000	$ 117,976,000	$ 18,957,000	$ (28,323,000)	$ 11,866,000	$ 97,494,000	$ (47,180,000)	$ 396,503,000	$ 33,857,000	$ 12,054,000
Net deferred tax assets (liabilities)	(1,113,082,000)				$ (720,566,000)				(1,113,082,000)	$ (720,566,000)
Deductible limit	1,000,000								1,000,000
Regular net operating loss carryforwards	641,400,000								641,400,000
Alternative minimum tax carryforwards	557,300,000								557,300,000
Deferred tax asset related to regular NOL	130,800,000								130,800,000
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, 2034
Oklahoma
Income Taxes [Line Items]
Valuation allowance on the deferred compensation plan	8,800,000								$ 8,800,000
Deferred compensation plan
Income Taxes [Line Items]
Valuation allowance on the deferred compensation plan	7,800,000								7,800,000
Alternative Minimum Tax
Income Taxes [Line Items]
AMT credit carryforwards that are not subject to limitation or expiration	$ 665,000								$ 665,000

Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effective Income Tax Rate Continuing Operations Tax Rate Reconciliation [Abstract]
Federal statutory tax rate	35.00%	35.00%	35.00%
State	3.10%	(2.30%)	0.70%
State apportionment rate change	(0.20%)	(14.90%)
Non-deductible executive compensation	0.20%	0.70%	1.40%
Valuation allowances	0.20%	3.50%	8.80%
Other	0.20%	0.60%	2.20%
Consolidated effective tax rate	38.50%	22.60%	48.10%

Income Taxes - Income Tax Expense (Benefit) Attributable to Income Before Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Components Of Income Tax Expense Benefit Continuing Operations [Abstract]
U.S. federal, Current
U.S. state and local, Current									1	$ (143)	(1,778)
Total, Current	$ (4)		$ (1)	$ 6	$ (143)		$ (25)	$ 25	1	(143)	(1,778)
U.S. federal, Deferred									361,152	58,527	11,873
U.S. state and local, Deferred									35,350	(24,527)	1,959
Total, Deferred	166,052	$ 93,522	117,977	18,951	(28,180)	$ 11,866	97,519	(47,205)	396,502	34,000	13,832
U.S. federal, Total									361,152	58,527	11,873
U.S. state and local, Total									35,351	(24,670)	181
Total income tax expense	$ 166,048	$ 93,522	$ 117,976	$ 18,957	$ (28,323)	$ 11,866	$ 97,494	$ (47,180)	$ 396,503	$ 33,857	$ 12,054

Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Deferred compensation	$ 9,286	$ 9,128
Total current	25,536	57,190
Deferred compensation	64,656	91,094
Valuation allowance	(16,599)	(14,781)
Total non-current	360,264	247,743
Deferred tax liabilities:
Total current	(141,123)	(5,776)
Total non-current	(1,357,759)	(1,019,723)
Net deferred tax liability	(1,113,082)	(720,566)
Current
Deferred tax assets:
Portion of asset retirement obligation	5,745	1,854
Cumulative mark-to-market loss	584	15,193
Net operating loss carryforward		23,079
Other	9,921	7,936
Deferred Tax Assets Non Current
Deferred tax assets:
Portion of asset retirement obligation	104,063	86,126
Cumulative mark-to-market loss	65
Net operating loss carryforward	176,812	57,266
Other	987	1,116
Equity compensation	25,833	22,800
AMT credits and other credits	4,447	4,122
Current
Deferred tax liabilities:
Net gain in AOCI related to hedge derivatives		(3,987)
Other	(2,350)	(1,789)
Cumulative mark-to-market gain	(138,773)
Deferred Tax Liabilities Non Current
Deferred tax liabilities:
Other	(310)	(2,542)
Cumulative mark-to-market gain	(15,410)	(6,424)
Depreciation, depletion and investments	$ (1,342,039)	$ (1,010,757)

Net 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, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Earnings Per Share Reconciliation [Abstract]

Net income, as reported

$ 284,054

$ 146,418

$ 171,389

$ 32,521

$ 28,171

$ 19,178

$ 143,983

$ (75,610)

$ 634,382

$ 115,722

$ 13,002

Participating basic earnings

^[1]

(10,725)

(1,975)

(460)

Basic net income attributed to common shareholders

623,657

113,747

12,542

Reallocation of participating earnings

^[1]

Diluted net income attributed to common shareholders

$ 623,705

$ 113,756

$ 12,542

Net income per common share:

Basic

$ 1.68

$ 0.87

$ 1.04

$ 0.20

$ 0.17

$ 0.12

$ 0.88

$ (0.47)

$ 3.81

$ 0.71

$ 0.08

Diluted

$ 1.68

$ 0.86

$ 1.04

$ 0.20

$ 0.17

$ 0.12

$ 0.88

$ (0.47)

$ 3.79

$ 0.70

$ 0.08

[1]

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

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

Net 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, 2014	Dec. 31, 2013	Dec. 31, 2012
Denominator:
Weighted average common shares outstanding – basic	163,625	160,438	159,431
Effect of dilutive securities:
Director and employee SARs and restricted stock Equity Awards	778	969	876
Weighted average common shares outstanding – diluted	164,403	161,407	160,307

Net Income Per Common Share - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	854,000
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	2,900,000

Suspended Exploratory Well Costs - Suspended Exploratory Well Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($) Project	Dec. 31, 2012 USD ($) Project
Extractive Industries [Abstract]
Balance at beginning of period	$ 6,964	$ 57,360	$ 93,388
Additions to capitalized exploratory well costs pending the determination of proved reserves	18,747	39,832	153,250
Reclassifications to wells, facilities and equipment based on determination of proved reserves	(15,735)	(84,840)	(184,298)
Divested wells			(4,980)
Capitalized exploratory well costs charged to expense	(6,980)	(5,388)
Balance at end of period	2,996	6,964	57,360
Less exploratory well costs that have been capitalized for a period of one year or less	$ (2,996)		(45,965)
Capitalized exploratory well costs that have been capitalized for a period greater than one year		$ 6,964	$ 11,395
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year \| Project		1	5

Indebtedness - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Interest capitalized during the period	$ 0	$ 0	$ 0

Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total debt	$ 2,350,000	$ 2,640,516
Total debt	3,073,000	3,140,516
Notes Payable to Banks \| 2.0% Bank Debt
Debt Instrument [Line Items]
Total debt	723,000	500,000
Senior Subordinated Notes \| 8.00% Notes Due 2019
Debt Instrument [Line Items]
Total debt		290,516
Senior Subordinated Notes \| 6.75% Notes Due 2020
Debt Instrument [Line Items]
Total debt	500,000	500,000
Senior Subordinated Notes \| 5.75% Notes Due 2021
Debt Instrument [Line Items]
Total debt	500,000	500,000
Senior Subordinated Notes \| 5.00% Notes Due 2022
Debt Instrument [Line Items]
Total debt	600,000	600,000
Senior Subordinated Notes \| 5.00% Notes Due 2023
Debt Instrument [Line Items]
Total debt	$ 750,000	$ 750,000

Indebtedness - Debt Outstanding (Parenthetical) (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Notes Payable to Banks \| 2.0% Bank Debt
Debt Instrument [Line Items]
Bank debt percentage	2.00%	2.00%
Senior Subordinated Notes \| 8.00% Notes Due 2019
Debt Instrument [Line Items]
Interest rate on senior subordinated notes	8.00%	8.00%
Discount on Senior Subordinated notes	$ 9,484
Senior Subordinated Notes \| 6.75% Notes Due 2020
Debt Instrument [Line Items]
Interest rate on senior subordinated notes	6.75%	6.75%
Senior Subordinated Notes \| 5.75% Notes Due 2021
Debt Instrument [Line Items]
Interest rate on senior subordinated notes	5.75%	5.75%
Senior Subordinated Notes \| 5.00% Notes Due 2022
Debt Instrument [Line Items]
Interest rate on senior subordinated notes	5.00%	5.00%
Senior Subordinated Notes \| 5.00% Notes Due 2023
Debt Instrument [Line Items]
Interest rate on senior subordinated notes	5.00%	5.00%

Indebtedness - Bank Debt - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($) CommercialBank	Dec. 31, 2013 USD ($)	Dec. 31, 2012
Debt Instrument [Line Items]
Bank Credit facility, maximum amount	$ 4,000,000
Bank Credit facility, initial borrowing	3,000,000
Bank commitments	$ 2,000,000
Percentage holding of commercial banks, Maximum	6.00%
Number of commercial banks included in current bank group \| CommercialBank	29
Maturity date of loan	Oct. 16, 2019
Bank debt	$ 723,000	$ 500,000
Undrawn letters of credit	105,300
Borrowing capacity available under the commitment amount	$ 1,200,000
Weighted average interest rate on the bank credit facility	2.00%	2.00%	2.20%
Commitment fee	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	1.50%
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	0.50%
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 Subordinated Notes and Early Extinguishment of Debt - Additional Information (Detail) - USD ($) $ in Thousands		3 Months Ended			12 Months Ended
	May 27, 2014	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Loss on early extinguishment of debt		$ 24,596	$ 12,280		$ 24,596	$ 12,280	$ 11,063
Subordinated Debt
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount					101.00%
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
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.
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
7.5% Senior Subordinated notes due 2017
Debt Instrument [Line Items]
Maximum redemption price of notes as percentage of principal amount							103.75%
Loss on early extinguishment of debt				$ 11,100

Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
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 debt to EBITDAX (as defined in the credit agreement) of no greater than 4.25 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. During an investment grade period in which Range has only one investment grade rating, an additional covenant is imposed whereby 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 to 1.0. We were in compliance with applicable covenants under the bank credit facility at December 31, 2014. 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, 2014, we were in compliance with these covenants.
Maximum
Debt Instrument [Line Items]
Ratio of debt to EBITDAX	4.25
Present Value Of Proved Reserves To Total Debt.	1.5
Minimum
Debt Instrument [Line Items]
Current ratio	1.0
Present Value Of Proved Reserves To Total Debt.	1.0

Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
2015
2016
2017
2018
2019	723,000
Thereafter	2,350,000
Total debt	$ 3,073,000	$ 3,140,516

Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Beginning of period	$ 230,077	$ 146,478
Liabilities incurred	8,602	8,731
Acquisitions	11,927
Liability released	(8,309)
Liabilities settled	(4,442)	(424)
Disposition of wells	(13,951)	(3,129)
Accretion expense	15,226	10,778
Change in estimate	48,333	67,643
End of period	287,463	230,077
Less current portion	(15,067)	(5,037)
Long-term asset retirement obligations	$ 272,396	$ 225,040

Capital Stock - Additional Information (Detail) - $ / shares	3 Months Ended												12 Months Ended
	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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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) - shares	12 Months Ended
Capital Stock (Detail) - shares	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity [Line Items]
Beginning balance	163,342,894	162,514,098	161,131,547
Stock options/SARs exercised	195,242	278,916	926,425
Restricted stock grants	270,062	401,122	354,674
Restricted stock units vested	244,413	119,480	57,824
Treasury shares	15,566	29,278	43,628
Ending balance	168,628,177	163,342,894	162,514,098
Common Stock
Equity [Line Items]
Equity offering	5,270,000	799,000	1,339,000
Common Stock \| Public Offerings
Equity [Line Items]
Equity offering	4,560,000

Derivative Activities - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($) MMBTU / d Counterparty Institution	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Derivative [Line Items]
Gain (Loss) Recognized in Income (Ineffective Portion)	$ 0	$ (2,930)	$ 1,125
Number of financial institutions with whom we conduct derivative activities \| Institution	15
Number of secured lenders not in banking credit facility \| Counterparty	1
Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 1,700
Volume Hedged \| MMBTU / d	35,164
Designated as Hedging Instrument
Derivative [Line Items]
Gains (Losses) in oil and gas sales related to settled hedging transactions	$ 10,200	$ 116,500	$ 236,300
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
Derivatives Excluding Basis Swaps
Derivative [Line Items]
Derivative assets liabilities at fair value net	$ 401,700

Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail)	Dec. 31, 2014 MMBTU / d bbl / d $ / MMBTU $ / bbl $ / gal
Natural Gas \| Collars \| 2015
Derivative [Line Items]
Volume Hedged \| MMBTU / d	145,000
Average floor price \| $ / MMBTU	4.07
Average cap price \| $ / MMBTU	4.56
Natural Gas \| Swaps \| 2015
Derivative [Line Items]
Volume Hedged \| MMBTU / d	412,390
Average hedge price \| $ / MMBTU	4.15
Natural Gas \| Swaps \| 2016
Derivative [Line Items]
Volume Hedged \| MMBTU / d	120,000
Average hedge price \| $ / MMBTU	4.15
Crude Oil \| Swaps \| 2015
Derivative [Line Items]
Volume Hedged \| bbl / d	9,626
Average hedge price \| $ / bbl	90.57
Crude Oil \| Swaps \| 2016
Derivative [Line Items]
Volume Hedged \| bbl / d	1,000
Average hedge price \| $ / bbl	91.43
Commodity Contract NGLs (C3 - Propane) \| Swaps \| 2015
Derivative [Line Items]
Volume Hedged \| bbl / d	2,245
Average hedge price \| $ / gal	0.95
Commodity Contract NGLs (C5 - Natural Gasoline) \| Swaps \| 2015 - first quarter
Derivative [Line Items]
Volume Hedged \| bbl / d	500
Average hedge price \| $ / gal	2.14

Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 404,118	$ 33,360
Gross Amounts Offset in the Balance Sheet	(755)	(19,706)
Net Amounts of Assets Presented in the Balance Sheet	403,363	13,654
Gross Amounts of Recognized (Liabilities)	(755)	(45,929)
Gross Amounts Offset in the Balance Sheet	755	19,706
Net Amounts of (Liabilities) Presented in the Balance Sheet		(26,223)
Natural Gas \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	198,740	4,240
Gross Amounts Offset in the Balance Sheet		(1,218)
Net Amounts of Assets Presented in the Balance Sheet	198,740	3,022
Gross Amounts of Recognized (Liabilities)		(4,790)
Gross Amounts Offset in the Balance Sheet		1,218
Net Amounts of (Liabilities) Presented in the Balance Sheet		(3,572)
Natural Gas \| Collars
Derivative [Line Items]
Gross Amounts of Recognized Assets	57,460	16,057
Gross Amounts Offset in the Balance Sheet		(7,671)
Net Amounts of Assets Presented in the Balance Sheet	57,460	8,386
Gross Amounts of Recognized (Liabilities)		(13,345)
Gross Amounts Offset in the Balance Sheet		7,671
Net Amounts of (Liabilities) Presented in the Balance Sheet		(5,674)
Natural Gas \| Basis Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	2,442	7,686
Gross Amounts Offset in the Balance Sheet	(755)	(7,686)
Net Amounts of Assets Presented in the Balance Sheet	1,687
Gross Amounts of Recognized (Liabilities)	(755)	(3,756)
Gross Amounts Offset in the Balance Sheet	755	7,686
Net Amounts of (Liabilities) Presented in the Balance Sheet		3,930
Crude Oil \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	128,578	3,567
Gross Amounts Offset in the Balance Sheet		(1,321)
Net Amounts of Assets Presented in the Balance Sheet	128,578	2,246
Gross Amounts of Recognized (Liabilities)		(4,711)
Gross Amounts Offset in the Balance Sheet		1,321
Net Amounts of (Liabilities) Presented in the Balance Sheet		(3,390)
Crude Oil \| Collars
Derivative [Line Items]
Gross Amounts of Recognized (Liabilities)		(398)
Net Amounts of (Liabilities) Presented in the Balance Sheet		(398)
Commodity Contract NGLs (C3 - Propane) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	14,727	826
Gross Amounts Offset in the Balance Sheet		(826)
Net Amounts of Assets Presented in the Balance Sheet	14,727
Gross Amounts of Recognized (Liabilities)		(18,172)
Gross Amounts Offset in the Balance Sheet		826
Net Amounts of (Liabilities) Presented in the Balance Sheet		(17,346)
Commodity Contract NGLs (C5 - Natural Gasoline) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets	2,171	121
Gross Amounts Offset in the Balance Sheet		(121)
Net Amounts of Assets Presented in the Balance Sheet	$ 2,171
Gross Amounts Offset in the Balance Sheet		121
Net Amounts of (Liabilities) Presented in the Balance Sheet		121
Commodity Contract NGLs (C4 - Natural Gasoline) \| Swaps
Derivative [Line Items]
Gross Amounts of Recognized Assets		863
Gross Amounts Offset in the Balance Sheet		(863)
Gross Amounts of Recognized (Liabilities)		(757)
Gross Amounts Offset in the Balance Sheet		863
Net Amounts of (Liabilities) Presented in the Balance Sheet		$ 106

Derivative Activities - Effects of Cash Flow Hedges and Other Hedges on Accumulated Other Comprehensive Income (Detail) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

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, 2014

Dec. 31, 2013

Dec. 31, 2012

$ (4,203)

Reclassification out of Accumulated Other Comprehensive Income

$ 872,214

$ 616,615

$ 765,524

$ 457,342

$ 428,086

$ 442,038

$ 673,356

$ 319,239

$ 2,711,695

1,862,719

$ 1,457,704

^[1]

6,236

73,470

Tax Effect

Tax Effect | Reclassification out of Accumulated Other Comprehensive Income

2,687

^[1]

(3,986)

(46,973)

Swaps | Before Tax

Swaps | Before Tax | Reclassification out of Accumulated Other Comprehensive Income

125

^[1]

4,544

15,171

Collars | Before Tax

Collars | Before Tax | Reclassification out of Accumulated Other Comprehensive Income

(7,015)

^[1]

$ 5,678

$ 105,272

[1]	For gains upon contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGLs and oil sales. For losses upon contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGLs and oil sales.

Derivative Activities - Effects of Non-Hedge Derivatives on Consolidated Statement of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									$ 383,520	$ (58,895)	$ 40,312
Gain (Loss) Recognized in Income (Ineffective Portion)									0	(2,930)	1,125
Derivative Fair Value Income (Loss)	$ 412,422	$ 142,057	$ (24,109)	$ (146,850)	$ (59,355)	$ (40,355)	$ 137,760	$ (99,875)	383,520	(61,825)	41,437
Swaps
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									367,484	(48,492)	11,601
Gain (Loss) Recognized in Income (Ineffective Portion)										(2,034)	(657)
Derivative Fair Value Income (Loss)									367,484	(50,526)	10,944
Re-purchased swaps
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)										1,323	9,313
Derivative Fair Value Income (Loss)										1,323	9,313
Collars
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									42,836	(15,166)	5,126
Gain (Loss) Recognized in Income (Ineffective Portion)										(896)	1,782
Derivative Fair Value Income (Loss)									42,836	(16,062)	6,908
Basis Swaps
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)									(26,800)	3,440	1,124
Derivative Fair Value Income (Loss)									$ (26,800)	$ 3,440	1,124
Call options
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)											13,178
Derivative Fair Value Income (Loss)											13,178
Put options
Derivative Financial Instruments [Line Items]
Gain (Loss) Recognized in Income (Non-hedge Derivatives)											(30)
Derivative Fair Value Income (Loss)											$ (30)

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, 2014	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Trading securities held in the deferred compensation plans	$ 68,454	$ 67,766
Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	344,216	(18,813)
Collars
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	57,460	2,314
Basis Swaps
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets liabilities at fair value net	1,687	3,930
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	68,454	67,776
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	344,216	(18,813)
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	2,314
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	$ 1,687	3,382
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		$ 548

Fair Value Measurements - Additional Information (Detail)	3 Months Ended				12 Months Ended
	Dec. 31, 2014 USD ($) Swaps	Jun. 30, 2014 USD ($)	Sep. 30, 2013 USD ($)	Jun. 30, 2013 USD ($)	Dec. 31, 2014 USD ($) Swaps	Dec. 31, 2013 USD ($) Swaps	Dec. 31, 2012 USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Interest and dividends					$ 911,000	$ 1,200,000	$ 1,400,000
Mark-to-market gain (loss)					(2,400,000)	3,900,000	4,700,000
Impairment	$ 3,033,000	$ 24,991,000	$ 7,012,000	$ 741,000	28,024,000	7,753,000	35,554,000
Mississippi
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties					5,500,000		31,100,000
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		3,200,000
Gulf Coast
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment on natural gas and oil properties						7,000,000
Surface Property \| Fair Value, Measurements, Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment						$ 741,000	$ 1,281,000
Basis Swaps \| Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Number of natural gas basis swap \| Swaps	0				0	4

Fair Value Measurements - Reconciliation of the Net Beginning and Ending Balances for Derivative Instruments (Detail) - Fair Value, Inputs, Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Beginning balance	$ 548
Changes in fair value of derivative instruments	2,979
Settlements received	$ (3,527)

Fair Value Measurements - Value of Assets Measured at Fair Value on Non Recurring Basis (Detail) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	$ 3,033	$ 24,991	$ 7,012	$ 741	$ 28,024	$ 7,753	$ 35,554
Fair Value, Measurements, Nonrecurring \| Natural Gas and Oil Properties
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value	$ 15,605				15,605	500	12,604
Impairment					$ 28,024	7,012	34,273
Fair Value, Measurements, Nonrecurring \| Surface Property
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair Value						5,550	6,269
Impairment						$ 741	$ 1,281

Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($)
$ in Thousands

Dec. 31, 2014

Dec. 31, 2013

Carrying Value

Assets:

$ 403,363

$ 13,654

Marketable securities

^[1]

68,454

67,766

Deferred compensation plan

(26,223)

Bank credit facility

^[2]

(723,000)

(500,000)

^[3]

(203,433)

(271,738)

Carrying Value | 8.00% Senior Subordinated Notes Due 2019

Carrying Value | 6.75% Senior Subordinated Notes Due 2020

^[2]

(290,516)

Carrying Value | 5.75% Senior Subordinated Notes Due 2021

^[2]

(500,000)

Carrying Value | 5.00% Senior Subordinated Notes Due 2022

^[2]

(500,000)

Carrying Value | 5.00% Senior Subordinated Notes Due 2023

^[2]

(600,000)

^[2]

(750,000)

Fair Value

Assets:

403,363

13,654

Marketable securities

^[1]

68,454

67,766

Deferred compensation plan

(26,223)

Bank credit facility

^[2]

(723,000)

(500,000)

^[3]

(203,433)

(271,738)

Fair Value | 8.00% Senior Subordinated Notes Due 2019

Fair Value | 6.75% Senior Subordinated Notes Due 2020

^[2]

(319,500)

Fair Value | 5.75% Senior Subordinated Notes Due 2021

^[2]

(523,125)

(541,250)

Fair Value | 5.00% Senior Subordinated Notes Due 2022

^[2]

(520,000)

(530,625)

Fair Value | 5.00% Senior Subordinated Notes Due 2023

^[2]

(601,500)

(588,750)

Summary of Performance Share Unit Awards outstanding, Number of Units

^[2]

$ (754,688)

$ (732,188)

[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 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 - Carrying Amounts and Fair Values of Financial Instruments (Parenthetical) (Detail) - Senior Subordinated Notes	Dec. 31, 2014	Dec. 31, 2013
8.00% Senior Subordinated Notes Due 2019
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on senior subordinated notes	8.00%	8.00%
6.75% Senior Subordinated Notes Due 2020
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on senior subordinated notes	6.75%	6.75%
5.75% Senior Subordinated Notes Due 2021
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on senior subordinated notes	5.75%	5.75%
5.00% Senior Subordinated Notes Due 2022
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on senior subordinated notes	5.00%	5.00%
5.00% Senior Subordinated Notes Due 2023
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Interest rate on senior subordinated notes	5.00%	5.00%

Stock-Based Compensation Plans - Additional Information (Detail) - shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock Options \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration term of stock options	5 years
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Awards granted	1,104	470,617	754,471
Vesting period	3 years
Stock Appreciation Rights (SARs) \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expiration term of stock options	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
Director Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Maximum number of common stock authorized to be issued under the Plans	450,000

Stock-Based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 70,681	$ 64,369	$ 52,770
Termination costs
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	2,999
Operating Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	4,208	2,755	2,415
Brokered Natural Gas and Marketing Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	3,523	1,852	1,765
Exploration Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	4,569	4,025	4,049
General and Administrative Expense
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Stock-based compensation expense	$ 55,382	$ 55,737	$ 44,541

Stock-Based Compensation Plans - Additional Information 1 (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2014 USD ($) Plans shares	Dec. 31, 2013 USD ($) shares	Dec. 31, 2012 USD ($) shares	Dec. 31, 2011 shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Acceleration of stock-based compensation expense	$ 10,000
Stock-based compensation expense	$ 70,681	$ 64,369	$ 52,770
Active equity-based stock plans \| Plans	2
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of stock option outstanding \| shares	1,966,549	2,582,074	3,433,362	4,558,609
Former Executive Chairman
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 6,700
Termination costs
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 2,999

Stock-Based Compensation Plans - Stock Option and SARs Activities (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Beginning Balance, Shares	2,582,074	3,433,362	4,558,609
Granted, Shares	1,104	470,617	754,471
Exercised, Shares	(616,563)	(1,269,323)	(1,860,367)
Expired/forfeited, Shares	(66)	(52,582)	(19,351)
Ending Balance, Shares	1,966,549	2,582,074	3,433,362
Beginning Balance, Weighted Average Exercise Price	$ 56.36	$ 52.52	$ 41.47
Granted, Weighted Average Exercise Price	81.74	75.82	64.14
Exercised, Weighted Average Exercise Price	45.45	53.24	30.20
Expired/forfeited, Weighted Average Exercise Price	46.44	53.56	48.00
Ending Balance, Weighted Average Exercise Price	$ 59.80	$ 56.36	$ 52.52

Stock-Based Compensation Plans - Outstanding SARs (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Number of outstanding Number of exercisable, Shares	1,966,549
Weighted Average Remaining Contractual Life (in years)	1 year 10 months 13 days
Weighted Average Exercise Price, Outstanding	$ 59.80	$ 56.36	$ 52.52	$ 41.47
Number of exercisable, Shares	1,521,832
Weighted Average Exercise Price, Exercisable	$ 56.64
Range of Exercise Prices One
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	31.13
Exercise Price, Maximum	$ 39.99
Number of outstanding Number of exercisable, Shares	3,260
Weighted Average Remaining Contractual Life (in years)	6 months 29 days
Weighted Average Exercise Price, Outstanding	$ 38.82
Number of exercisable, Shares	3,260
Weighted Average Exercise Price, Exercisable	$ 38.82
Range of Exercise Prices Two
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	40.00
Exercise Price, Maximum	$ 49.99
Number of outstanding Number of exercisable, Shares	542,206
Weighted Average Remaining Contractual Life (in years)	5 months 27 days
Weighted Average Exercise Price, Outstanding	$ 46.47
Number of exercisable, Shares	542,206
Weighted Average Exercise Price, Exercisable	$ 46.47
Range of Exercise Prices Three
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	50.00
Exercise Price, Maximum	$ 59.99
Number of outstanding Number of exercisable, Shares	355,856
Weighted Average Remaining Contractual Life (in years)	1 year 4 months 17 days
Weighted Average Exercise Price, Outstanding	$ 52.35
Number of exercisable, Shares	355,856
Weighted Average Exercise Price, Exercisable	$ 52.35
Range of Exercise Prices Four
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	60.00
Exercise Price, Maximum	$ 69.99
Number of outstanding Number of exercisable, Shares	614,909
Weighted Average Remaining Contractual Life (in years)	2 years 3 months 29 days
Weighted Average Exercise Price, Outstanding	$ 64.18
Number of exercisable, Shares	422,546
Weighted Average Exercise Price, Exercisable	$ 64.21
Range of Exercise Prices Five
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	70.00
Exercise Price, Maximum	$ 79.99
Number of outstanding Number of exercisable, Shares	448,418
Weighted Average Remaining Contractual Life (in years)	3 years 3 months 18 days
Weighted Average Exercise Price, Outstanding	$ 75.88
Number of exercisable, Shares	196,064
Weighted Average Exercise Price, Exercisable	$ 76.30
Range of Exercise Prices Six
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items]
Exercise Price, Minimum	80.00
Exercise Price, Maximum	$ 81.15
Number of outstanding Number of exercisable, Shares	1,900
Weighted Average Remaining Contractual Life (in years)	3 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 Plans - Weighted Average Grant Date Fair Value of SARs (Detail) - Stock Appreciation Rights (SARs) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Weighted Average Assumptions For Fair Values Of Stock Options [Line Items]
Weighted average exercise price per share	$ 81.74	$ 75.82	$ 64.14
Expected annual dividend yield	0.20%	0.21%	0.25%
Expected life in years	4 years 3 months 18 days	3 years 8 months 12 days	3 years 8 months 12 days
Expected volatility	33.00%	35.00%	45.00%
Risk-free interest rate	1.40%	0.60%	0.50%
Weighted average grant date fair value per share	$ 23.17	$ 20.20	$ 21.32

Stock-Based Compensation Plans - Additional Information 2 (Detail) - USD ($) $ / shares in Units, $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total intrinsic value of stock options and SARs exercised	$ 27,100	$ 30,300	$ 61,000
Aggregate intrinsic value of the awards outstanding	4,200
Aggregate intrinsic value of the awards exercisable	$ 4,200
Weighted average remaining contractual life of awards exercisable	1 year 7 months 6 days
Stock-based compensation expense	$ 70,681	64,369	$ 52,770
Stock Appreciation Rights (SARs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of fully vested awards and awards expected to vest	2.0
Weighted average exercise price of fully vested awards and awards expected to vest	$ 59.72
Weighted average exercise price of fully vested awards and awards expected to vest in years	1 year 10 months 24 days
Aggregate intrinsic value of fully vested awards and awards expected to vest	$ 4,200
Unrecognized compensation related to Awards	$ 3,900
Weighted average period	1 year 1 month 6 days
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation related to Awards	$ 10,500
Weighted average period	2 years 3 months 18 days
Stock-based compensation expense	$ 7,700	$ 0

Stock-Based Compensation Plans - PSUA Activity (Detail) - Performance Shares

12 Months Ended

Dec. 31, 2014

$ / shares

Outstanding, Beginning Balance | shares

Granted | shares

227,929

^[1]

Vested | shares

(92,077)

^[2]

Forfeited | shares

(1,511)

Outstanding, Ending Balance | shares

134,341

Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value

Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares

$ 0

Granted, weighted average grant date fair value | $ / shares

86.14

^[1]

Vested, weighted average grant date fair value | $ / shares

86.23

^[2]

Forfeited, weighted average grant date fair value | $ / shares

82.60

Outstanding, Ending Balance, weighted average grant date fair value | $ / shares

$ 86.11

[1]	Amounts granted 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]	Primarily represents PSU awards granted to our prior executive chairman for the 2013 calendar year while he was a Range officer.

Stock-Based Compensation Plans - PSUA Activity (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares on performance units granted	0.00%
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Actual payout of shares on performance units granted	150.00%

Stock-Based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Shares

12 Months Ended

Dec. 31, 2014

$ / shares

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Risk-free interest rate

0.77%

Expected volatility

33.00%

Granted, weighted average grant date fair value

$ 86.14

^[1]

[1]	Amounts granted 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.

Stock-Based Compensation Plans - Additional Information 3 (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense	$ 70,681	$ 64,369	$ 52,770
Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	356,194	402,053	364,082
Stock-based compensation expense	$ 26,300	$ 19,700	$ 11,800
Unrecognized compensation related to Awards	$ 26,900
Weighted average period	1 year 9 months 18 days
Vesting period	3 years	3 years	3 years
Granted, weighted average grant date fair value	$ 84.87	$ 71.26	$ 63.44
Restricted Stock Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	272,052	424,809	380,808
Stock-based compensation expense	$ 25,200	$ 27,400	$ 21,500
Unrecognized compensation related to Awards	$ 22,000
Weighted average period	1 year 9 months 18 days
Vesting period	3 years	3 years	3 years
Granted, weighted average grant date fair value	$ 87.34	$ 75.53	$ 64.06
Proceeds received from sale of stock held in deferred compensation plan	$ 16,000
Restricted Stock Liability Awards \| Non Employee Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	64,000	18,000	14,700
Restricted Stock Liability Awards \| Employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	208,000	407,000	366,300

Stock-Based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	385,063	349,156	221,609
Granted	356,194	402,053	364,082
Vested	(354,237)	(315,535)	(208,802)
Forfeited	(26,605)	(50,611)	(27,733)
Outstanding, Ending Balance	360,415	385,063	349,156
Outstanding, Beginning Balance, weighted average grant date fair value	$ 68.24	$ 59.08	$ 49.64
Granted, weighted average grant date fair value	84.87	71.26	63.44
Vested, weighted average grant date fair value	72.85	62.43	56.73
Forfeited, weighted average grant date fair value	75.66	65.29	58.65
Outstanding, Ending Balance, weighted average grant date fair value	$ 79.60	$ 68.24	$ 59.08
Liability Awards
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Beginning Balance	389,013	423,478	487,244
Granted	272,052	424,809	380,808
Vested	(356,413)	(437,570)	(438,283)
Forfeited	(148)	(21,704)	(6,291)
Outstanding, Ending Balance	304,504	389,013	423,478
Outstanding, Beginning Balance, weighted average grant date fair value	$ 71.02	$ 58.91	$ 48.76
Granted, weighted average grant date fair value	87.34	75.53	64.06
Vested, weighted average grant date fair value	75.52	64.36	52.17
Forfeited, weighted average grant date fair value	77.35	57.31	54.54
Outstanding, Ending Balance, weighted average grant date fair value	$ 80.33	$ 71.02	$ 58.91

Stock-Based Compensation Plans - Additional Information 4 (Detail) - USD ($) $ in Thousands, shares in Millions	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
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									$ 5,800	$ 5,100
Deferred compensation plan vesting period									3 years
Deferred compensation plan	$ (36,836)	$ (46,198)	$ 10,519	$ (2,035)	$ 22,039	$ (2,225)	$ (6,878)	$ 42,360	$ (74,550)	$ 55,296	$ 7,203
Shares held in rabbi trust total	2.8				2.8				2.8	2.8
Vested shares held in rabbi trust	2.5				2.4				2.5	2.4

Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Net cash provided from operating activities included:

Income taxes (refunded from) paid to taxing authorities

$ (156)

$ (347)

$ 386

Interest paid

165,530

159,137

153,249

Non-cash investing and financing activities included:

Asset retirement costs capitalized, net

^[1]

56,822

76,373

57,982

Increase (decrease) in accrued capital expenditures

$ 150,604

$ 27,079

$ (94,121)

[1]	Includes cost incurred whether capitalized or expensed.

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) bbl / d Mcfe / d	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)
Commitments And Contingencies Disclosure [Line Items]
Rent expense under operating leases \| $	$ 13.3	$ 13.1	$ 13.8
Minimum remaining terms of leases on undeveloped acreage, in years	3 years
Maximum remaining terms of leases on undeveloped acreage, in years	5 years
Hydraulic Fracturing
Commitments And Contingencies Disclosure [Line Items]
Contractual Obligation, Due in Next Twelve Months \| $	$ 12.0
Minimum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	5 years
Minimum \| 2015
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification in bbls per day	10,000
Maximum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract	20 years
Maximum \| 2015
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification in bbls per day	20,000
Maximum \| 2017
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification in bbls per day	30,000
Maximum \| 2018
Commitments And Contingencies Disclosure [Line Items]
Delivery commitments contingent upon pipeline construction or modification in bbls per day	45,000
Natural Gas \| Minimum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification \| Mcfe / d	7,000
Natural Gas \| Maximum
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification \| Mcfe / d	400,000
Ethane
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification	20,000
Propane
Commitments And Contingencies Disclosure [Line Items]
Transportation and gathering commitments contingent upon pipeline construction or modification	20,000

Commitments and Contingencies - Future Minimum Lease Commitments (Detail) $ in Thousands	Dec. 31, 2014 USD ($)
Commitments And Contingencies Disclosure [Abstract]
2015	$ 16,557
2016	12,700
2017	7,292
2018	5,660
2019	4,399
Thereafter	12,830
Operating Lease Obligations	$ 59,438

Commitments and Contingencies - Schedule of Future Minimum Transportation and Gathering Fees (Detail)
$ in Thousands

Dec. 31, 2014

USD ($)

^[1]

Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract]

$ 342,204

366,836

356,789

321,385

317,627

1,842,410

Transportation and Gathering Contracts

$ 3,547,251

[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.

Commitments and Contingencies - Future Delivery Commitments (Detail)	12 Months Ended
	Dec. 31, 2014 MMBTU / d bbl / d
2015 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	313,180
2015 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2016 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	268,055
2016 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2017 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	139,840
2017 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2018 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	30,000
2018 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2019 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	30,000
2019 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2020 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	30,000
2020 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2021 \| Natural Gas
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production \| MMBTU / d	30,000
2021 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000
2022-2028 \| Ethane
Commitments And Contingencies Disclosure [Line Items]
Oil and Gas Delivery Commitments and Contracts, Daily Production	15,000

Equity Method Investments - Additional Information (Detail) - USD ($)		1 Months Ended		6 Months Ended	12 Months Ended
	Jun. 16, 2014	Sep. 30, 2013	May 31, 2007	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2006
Schedule Of Equity Method Investments [Line Items]
Income (Loss) from equity method investments	$ 0				$ (3,095,000)	$ 2,973,000	$ (5,670,000)
Whipstock Natural Gas Services Llc
Schedule Of Equity Method Investments [Line Items]
Percentage ownership interest						50.00%		50.00%
Cash contributed for investment								$ 11,700,000
Proceeds from sale of equity method investments		$ 7,000,000
Equity method investment, Realized gain (loss) on disposal		$ 4,400,000
Nora Gathering, LLC
Schedule Of Equity Method Investments [Line Items]
Percentage ownership interest					50.00%
Cash contributed for investment			$ 94,700,000
Additional contributions made to fund expansion					$ 0	$ 0	0
Income (Loss) from equity method investments				$ (277,000)		(146,000)	(1,200,000)
Reduction in equity to eliminate the profit from gathering and transportation fees				$ 3,100,000		7,700,000	7,500,000
Cash distribution from investment					$ 7,000,000	$ 9,000,000	$ 12,800,000
EQT Corporation
Schedule Of Equity Method Investments [Line Items]
Equity method investment remaining ownership percentage	50.00%

Office Closing and Exit Costs - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014
Restructuring And Related Activities [Abstract]
Termination costs	$ 8,371	$ 8,371

Office Closing and Exit Costs - Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014
Exit costs included in accrued liabilities in consolidated balance sheet
Accrued termination costs	$ 8,371	$ 8,371
Ending balance	$ 8,371	$ 8,371

Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Selected Quarterly Financial Information [Line Items]
Gain on the sale of assets	$ 3,760	$ 167	$ 282,064	$ (353)	$ 3,162	$ 6,008	$ 83,287	$ (166)	$ 285,638	$ 92,291	$ 49,132
General and administrative	$ 52,363	$ 54,963	56,888	$ 49,212	60,207	$ 44,919	101,987	84,058	$ 213,426	291,171	$ 173,813
State apportionment rate adjustments					$ 21,200					$ 21,200
Conger Exchange Transaction
Selected Quarterly Financial Information [Line Items]
Gain on the sale of assets			$ 280,100
Drummond Legal Settlement
Selected Quarterly Financial Information [Line Items]
General and administrative							52,500	$ 35,000
Delaware and Permian Basin Properties
Selected Quarterly Financial Information [Line Items]
Gain on the sale of assets							$ 79,400

Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and other income:
Natural gas, NGLs and oil sales	$ 416,388	$ 446,067	$ 477,517	$ 572,017	$ 448,545	$ 431,214	$ 437,678	$ 398,239	$ 1,911,989	$ 1,715,676	$ 1,351,694
Derivative fair value (loss) income	412,422	142,057	(24,109)	(146,850)	(59,355)	(40,355)	137,760	(99,875)	383,520	(61,825)	41,437
(Loss) gain on the sale of assets	3,760	167	282,064	(353)	3,162	6,008	83,287	(166)	285,638	92,291	49,132
Brokered natural gas, marketing and other	39,644	28,324	30,052	32,528	35,734	45,171	14,631	21,041	130,548	116,577	15,441
Total revenues and other income	872,214	616,615	765,524	457,342	428,086	442,038	673,356	319,239	2,711,695	1,862,719	1,457,704
Costs and expenses:
Direct operating	37,961	37,792	34,935	39,795	34,360	30,907	32,636	30,188	150,483	128,091	115,905
Transportation, gathering and compression	89,542	84,777	76,809	74,161	66,820	60,958	66,048	62,416	325,289	256,242	192,445
Production and ad valorem taxes	11,923	10,110	10,844	11,678	11,290	11,454	11,113	11,383	44,555	45,240	67,120
Brokered natural gas and marketing	32,370	28,706	34,775	34,129	41,692	51,117	16,662	22,315	129,980	131,786	20,434
Exploration	23,638	11,443	13,621	14,846	14,065	20,496	13,068	16,780	63,548	64,409	69,807
Abandonment and impairment of unproved properties	14,308	13,444	9,332	9,995	5,852	11,692	19,156	15,218	47,079	51,918	125,278
General and administrative	52,363	54,963	56,888	49,212	60,207	44,919	101,987	84,058	213,426	291,171	173,813
Termination costs	8,371								8,371
Deferred compensation plan	(36,836)	(46,198)	10,519	(2,035)	22,039	(2,225)	(6,878)	42,360	(74,550)	55,296	7,203
Interest expense	38,900	39,188	45,488	45,401	44,955	44,321	45,071	42,210	168,977	176,557	168,798
Loss on early extinguishment of debt			24,596				12,280		24,596	12,280	11,063
Depletion, depreciation and amortization	146,539	142,450	133,361	128,682	126,958	130,343	119,995	115,101	551,032	492,397	445,228
Impairment of proved properties and other assets	3,033		24,991			7,012	741		28,024	7,753	35,554
Total costs and expenses	422,112	376,675	476,159	405,864	428,238	410,994	431,879	442,029	1,680,810	1,713,140	1,432,648
Income before income taxes	450,102	239,940	289,365	51,478	(152)	31,044	241,477	(122,790)	1,030,885	149,579	25,056
Income tax expense (benefit):
Current	(4)		(1)	6	(143)		(25)	25	1	(143)	(1,778)
Deferred	166,052	93,522	117,977	18,951	(28,180)	11,866	97,519	(47,205)	396,502	34,000	13,832
Total income tax expense	166,048	93,522	117,976	18,957	(28,323)	11,866	97,494	(47,180)	396,503	33,857	12,054
Net income	$ 284,054	$ 146,418	$ 171,389	$ 32,521	$ 28,171	$ 19,178	$ 143,983	$ (75,610)	$ 634,382	$ 115,722	$ 13,002
Net (loss) income per common share:
Basic	$ 1.68	$ 0.87	$ 1.04	$ 0.20	$ 0.17	$ 0.12	$ 0.88	$ (0.47)	$ 3.81	$ 0.71	$ 0.08
Diluted	$ 1.68	$ 0.86	$ 1.04	$ 0.20	$ 0.17	$ 0.12	$ 0.88	$ (0.47)	$ 3.79	$ 0.70	$ 0.08

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, 2014

Dec. 31, 2013

Dec. 31, 2012

Natural gas and oil properties:

Properties subject to depletion

^[1]

$ 9,624,725

$ 8,225,859

$ 7,368,308

Unproved properties

^[1]

943,246

807,022

743,467

Total

^[1]

10,567,971

9,032,881

8,111,775

Accumulated depletion and depreciation

^[1]

(2,590,398)

(2,274,444)

(2,015,591)

Natural gas and oil properties, successful efforts method, net

^[1]

$ 7,977,573

$ 6,758,437

$ 6,096,184

[1]	Includes capitalized asset retirement costs and the associated accumulated amortization.

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, 2014

Dec. 31, 2013

Dec. 31, 2012

Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]

Acquisitions

^[1],[2]

$ 404,252

Acreage purchases

^[1]

226,475

$ 137,538

$ 188,843

Development

^[1]

1,119,896

938,668

1,049,129

Gas gathering facilities:

Development

^[1]

13,137

47,086

41,035

Subtotal

^[1]

2,008,233

1,377,443

1,658,630

Exploration costs incurred

^[1]

56,822

76,373

57,982

Total costs incurred

^[1]

2,065,055

1,453,816

1,716,612

Drilling

Exploration:

^[1]

180,925

189,742

309,816

Expense

Exploration:

Exploration costs incurred

^[1]

58,979

60,384

65,758

Stock-based compensation expense

Exploration:

Exploration costs incurred

^[1]

$ 4,569

$ 4,025

$ 4,049

[1]	Includes cost incurred whether capitalized or expensed.
[2]	See also Note 3 for additional information related to the 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.

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]

Acquisition Costs, Period Cost

^[1],[2]

$ 404,252

Conger Exchange Transaction

^[1]

56,822

$ 76,373

$ 57,982

Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]

Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]

11,900

Gas Gathering Assets

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 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 Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($) Mcfe MMcfe $ / MMBTU $ / bbl $ / Mcf MBbls	Dec. 31, 2013 MMcfe $ / MMBTU $ / bbl $ / Mcf MBbls	Dec. 31, 2012 MMcfe $ / MMBTU $ / bbl $ / Mcf MBbls
Reserve Quantities [Line Items]
Percentage of proved resources reviewed by consultants	96.00%
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
Proved reserves from drilling activities and evaluations of proved areas \| MMcfe	2,398,709	1,732,944	1,767,202
Reserve attributable to natural gas	58.00%	49.00%	56.00%
Positive performance energy revisions for ethane reserves \| MMcfe	1,170,000	676,000	307,000
Revisions of previous estimates \| MMcfe	90,822	448,898	109,036
Proved undeveloped reserves dropped \| MMcfe	611,341
Cost spent on undeveloped reserves transferred to developed reserves \| $	$ 591.0
Volume of Mmcfe of reserves that have been reported for five or more years included in proved undeveloped reserves, approximately \| Mcfe	3
Period for which the reserves have been reported to be included in proved undeveloped reserves	Five or more years.
Maximum
Reserve Quantities [Line Items]
Percentage of proved undeveloped reserves	1.00%
Year 2015
Reserve Quantities [Line Items]
Estimated future development costs \| $	$ 981.1
Year 2016
Reserve Quantities [Line Items]
Estimated future development costs \| $	1,000.0
Year 2017
Reserve Quantities [Line Items]
Estimated future development costs \| $	$ 993.5
Crude Oil
Reserve Quantities [Line Items]
Estimate reserve information average realized prices \| $ / bbl	79.04	86.66	86.91
NGLs
Reserve Quantities [Line Items]
Estimate reserve information average realized prices \| $ / bbl	27.20	25.93	32.23
Positive performance revisions for ethane reserves \| MBbls	264,300	155,800	51,200
Natural Gas
Reserve Quantities [Line Items]
Estimate reserve information average realized prices \| $ / Mcf	4.14	3.75	2.75
Crude Oil and NGL
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices \| $ / bbl	94.42	97.33	95.05
Natural Gas, Per Thousand Cubic Feet
Reserve Quantities [Line Items]
Benchmark price used for calculating average realized prices \| $ / MMBTU	4.35	3.67	2.76

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Proved Developed and Undeveloped Reserves (Detail)

12 Months Ended

Dec. 31, 2014

MMcfe

MMcf

MBbls

Dec. 31, 2013

MMcfe

MMcf

MBbls

Dec. 31, 2012

MMcfe

MMcf

MBbls

Extensions, discoveries and additions | MMcfe

Revisions | MMcfe

90,822

448,898

109,036

2,398,709

1,732,944

1,767,202

Proved undeveloped reserves | MMcfe

4,960,468

4,009,608

Natural Gas

Extensions, discoveries and additions | MMcf

Beginning Balance | MMcf

5,665,645

4,792,676

4,009,676

Revisions | MMcf

(30,566)

384,825

76,925

1,393,108

853,746

996,059

Purchases | MMcf

262,813

Property sales | MMcf

(81,238)

(101,074)

(73,429)

Production | MMcf

(286,926)

(264,528)

(216,555)

Ending Balance | MMcf

6,922,836

5,665,645

4,792,676

Proved developed reserves | MMcf

3,583,051

2,797,483

2,373,604

Proved undeveloped reserves | MMcf

3,339,785

2,868,162

2,419,072

NGLs

Extensions, discoveries and additions

Beginning Balance

374,412

240,399

142,515

Revisions

19,716

7,743

3,036

154,664

135,810

113,392

Purchases

Property sales

(14,064)

(286)

(11,575)

Production

(18,821)

(9,254)

(6,969)

Ending Balance

515,907

374,412

240,399

Proved developed reserves

270,271

206,477

154,984

Proved undeveloped reserves

245,636

167,935

85,415

Crude Oil and Condensate

Extensions, discoveries and additions

Beginning Balance

48,360

45,082

31,532

Revisions

515

2,935

2,316

12,936

10,723

15,131

Purchases

Property sales

(9,083)

(6,553)

(1,046)

Production

(4,070)

(3,827)

(2,851)

Ending Balance

48,658

48,360

45,082

Proved developed reserves

24,180

26,054

25,667

Proved undeveloped reserves

24,478

22,306

19,415

Natural Gas Equivalents

Beginning Balance | MMcfe

^[1]

8,202,274

6,505,570

5,053,961

Revisions | MMcfe

^[1]

90,822

448,898

109,036

Extensions, discoveries and additions | MMcfe

^[1]

2,398,709

1,732,944

1,767,202

Purchases | MMcfe

^[1]

262,813

Property sales | MMcfe

^[1]

(220,122)

(142,116)

(149,153)

Production | MMcfe

^[1]

(424,267)

(343,022)

(275,476)

Ending Balance | MMcfe

^[1]

10,310,229

8,202,274

6,505,570

Proved developed reserves | MMcfe

^[1]

5,349,761

4,192,666

3,457,502

Proved undeveloped reserves | MMcfe

^[1]

4,960,468

4,009,608

3,048,068

[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 Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves for 2013 (Mmcfe) (Detail)

12 Months Ended

Dec. 31, 2014

MMcfe

Beginning proved undeveloped reserves at December 31, 2013

4,009,608

Undeveloped reserves transferred to developed

(620,167)

Revisions

(147,019)

^[1]

Purchases/ (sales)

(58,045)

Extension and discoveries

1,776,091

Ending proved undeveloped reserves at December 31, 2014

4,960,468

[1]	Includes 611,341 Mmcfe of proved undeveloped reserves dropped due to the five year rule.

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves for 2013 (Mmcfe) (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014 MMcfe
Extractive Industries [Abstract]
Proved undeveloped reserves dropped	611,341

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, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011