Antero Resources (AR) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 27, 2014
Document and Entity Information	'	'
Entity Registrant Name	'ANTERO RESOURCES Corp	'
Entity Central Index Key	'0001433270	'
Document Type	'10-K	'
Document Period End Date	31-Dec-13	'
Amendment Flag	'false	'
Current Fiscal Year End Date	'--12-31	'
Entity Well-known Seasoned Issuer	'No	'
Entity Voluntary Filers	'Yes	'
Entity Current Reporting Status	'Yes	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Public Float	$2.60	'
Entity Common Stock, Shares Outstanding	'	262,049,659
Document Fiscal Period Focus	'FY	'
Document Fiscal Year Focus	'2013	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$17,487	$18,989
Accounts receivable - trade, net of allowance for doubtful accounts of $174 and $1,251 in 2012 and 2013, respectively	30,610	21,296
Notes receivable - short-term portion	2,667	4,555
Accrued revenue	96,825	46,669
Derivative instruments	183,000	160,579
Other	2,975	22,518
Total current assets	333,564	274,606
Natural gas properties, at cost (successful efforts method):	'	'
Unproved properties	1,513,136	1,243,237
Proved properties	3,621,672	1,682,297
Fresh water distribution systems	231,684	6,835
Gathering systems and facilities	584,626	168,930
Other property and equipment	15,757	9,517
Property and equipment, gross	5,966,875	3,110,816
Less accumulated depletion, depreciation, and amortization	-407,219	-173,343
Property and equipment, net	5,559,656	2,937,473
Derivative instruments	677,780	371,436
Notes receivable - long-term portion	'	2,667
Other assets, net	42,581	32,611
Total assets	6,613,581	3,618,793
Current liabilities:	'	'
Accounts payable	370,640	181,478
Accrued liabilities	77,126	58,829
Revenue distributions payable	96,589	46,037
Current debt	'	25,000
Deferred income tax liability	69,191	62,620
Derivative instruments	646	'
Other	8,037	2,332
Total current liabilities	622,229	376,296
Long-term liabilities:	'	'
Long-term debt	2,078,999	1,444,058
Deferred income tax liability	278,580	91,692
Other long-term liabilities	35,113	33,010
Total liabilities	3,014,921	1,945,056
Stockholders'/Members' Equity:	'	'
Members' equity of Antero Resources LLC	'	1,460,947
Common stock of Antero Resources Corporation, $0.01 par value; authorized - 1,000,000,000 shares; issued and outstanding 262,049,659 shares	2,620	'
Preferred stock of Antero Resources Corporation, $0.01 par value; authorized - 50,000,000 shares; none issued	'	'
Additional paid-in capital	3,402,180	'
Accumulated earnings	193,860	212,790
Total equity	3,598,660	1,673,737
Total liabilities and equity	$6,613,581	$3,618,793

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Consolidated Balance Sheets	'	'
Accounts receivable - trade, allowance for doubtful accounts	$1,251	$174
Common stock, par value (in dollars per share)	$0.01	$0.01
Common stock, authorized shares	1,000,000,000	1,000,000,000
Common stock, shares issued	262,049,659	262,049,659
Common stock, shares outstanding	262,049,659	262,049,659
Preferred stock, par value (in dollars per share)	$0.01	$0.01
Preferred stock, authorized shares	50,000,000	50,000,000
Preferred stock, shares issued	0	0

Consolidated_Statements_of_Ope

Consolidated Statements of Operations and Comprehensive Income (Loss) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue:	'	'	'
Natural gas sales	$689,198,000	$259,743,000	$195,116,000
Natural gas liquids sales	111,663,000	3,719,000	'
Oil sales	20,584,000	1,520,000	173,000
Commodity derivative fair value gains	491,689,000	179,546,000	496,064,000
Gain on sale of gathering system	'	291,190,000	'
Total revenue	1,313,134,000	735,718,000	691,353,000
Operating expenses:	'	'	'
Lease operating	9,439,000	6,243,000	4,608,000
Gathering, compression, processing, and transportation	218,428,000	91,094,000	37,315,000
Production and ad valorem taxes	50,481,000	20,210,000	11,915,000
Exploration	22,272,000	14,675,000	4,034,000
Impairment of unproved properties	10,928,000	12,070,000	4,664,000
Depletion, depreciation, and amortization	233,876,000	102,026,000	55,716,000
Accretion of asset retirement obligations	1,065,000	101,000	76,000
General and administrative (including $365,280 of stock compensation in 2013)	425,438,000	45,284,000	33,342,000
Loss on sale of assets	'	'	8,700,000
Total operating expenses	971,927,000	291,703,000	160,370,000
Operating income	341,207,000	444,015,000	530,983,000
Other expenses:	'	'	'
Interest	-136,617,000	-97,510,000	-74,404,000
Loss on early extinguishment of debt	-42,567,000	'	'
Interest rate derivative fair value loss	'	'	-94,000
Total other expenses	-179,184,000	-97,510,000	-74,498,000
Income from continuing operations before income taxes and discontinued operations	162,023,000	346,505,000	456,485,000
Provision for income taxes	-186,210,000	-121,229,000	-185,297,000
Income from continuing operations	-24,187,000	225,276,000	271,188,000
Discontinued operations:	'	'	'
Income (loss) from results of operations and sale of discontinued operations, net of income tax (expense) benefit of $(45,155), $272,533, and $(3,249) in 2011, 2012, and 2013, respectively	5,257,000	-510,345,000	121,490,000
Net income (loss) and comprehensive income (loss)	($18,930,000)	($285,069,000)	$392,678,000
Earnings (loss) per share:	'	'	'
Continuing operations (in dollars per share)	($0.09)	$0.86	$1.04
Discontinued operations (in dollars per share)	$0.02	($1.95)	$0.46
Total (in dollars per share)	($0.07)	($1.09)	$1.50
Earnings (loss) per share - assuming dilution:	'	'	'
Continuing operations (in dollars per share)	($0.09)	$0.86	$1.04
Discontinued operations (in dollars per share)	$0.02	($1.95)	$0.46
Total (in dollars per share)	($0.07)	($1.09)	$1.50

Consolidated_Statements_of_Ope1

Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Consolidated Statements of Operations and Comprehensive Income (Loss)	'	'	'
Stock compensation	$365,280	'	'
Discontinued operations, income tax (expense) benefit	($3,249)	$272,533	($45,155)

Consolidated_Statements_of_Equ

Consolidated Statements of Equity (USD $)	Total	Members' equity	Common Stock	Additional paid-in capital	Accumulated earnings
In Thousands, unless otherwise specified
Balances at Dec. 31, 2010	$1,594,987	$1,489,806	'	'	$105,181
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'
Distribution to members	-28,859	-28,859	'	'	'
Net loss and comprehensive loss	392,678	'	'	'	392,678
Balances at Dec. 31, 2011	1,958,806	1,460,947	'	'	497,859
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'
Net loss and comprehensive loss	-285,069	'	'	'	-285,069
Balances at Dec. 31, 2012	1,673,737	1,460,947	'	'	212,790
Increase (Decrease) in Stockholders' Equity	'	'	'	'	'
Net loss and comprehensive loss	-18,930	'	'	'	-18,930
Merger of Antero Resources LLC and Antero Resources Corporation	'	-1,460,947	2,244	1,458,703	'
Issuance of 37,674,659 shares of $0.01 par value common stock in public offering, net of underwriter discounts and offering costs of $79,112	1,578,573	'	376	1,578,197	'
Capital contribution for stock compensation of affiliate	364,957	'	'	364,957	'
Stock compensation related to company plan	323	'	'	323	'
Balances at Dec. 31, 2013	$3,598,660	'	$2,620	$3,402,180	$193,860

Consolidated_Statements_of_Equ1

Consolidated Statements of Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Consolidated Statements of Equity and Comprehensive Income (Loss)	'
Sale of common stock (in shares)	37,674,659
Common stock, par value (in dollars per share)	$0.01
Issuance of common stock in public offering, net of underwriter discounts and offering costs	$79,112

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income (loss)	($18,930)	($285,069)	$392,678
Adjustment to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Depletion, depreciation, amortization, and depletion	234,941	102,127	55,792
Impairment of unproved properties	10,928	12,070	4,664
Derivative fair value gains	-491,689	-179,546	-495,970
Cash receipts for settled derivatives	163,570	178,491	45,638
Deferred income taxes	190,210	106,229	185,297
(Gain) loss on sale of assets	'	-291,190	8,700
Stock compensation	365,280	'	'
Loss on early extinguishment of debt	42,567	'	'
Loss (gain) on sale of discontinued operations	-8,506	795,945	'
Depletion, depreciation, amortization, and impairment of unproved properties - discontinued operations	'	90,096	126,041
Derivative fair value gains - discontinued operations	'	-46,358	-180,130
Cash receipts for settled derivatives - discontinued operations	'	92,166	66,654
Deferred income taxes - discontinued operations	3,249	-272,553	45,155
Other	1,173	4,960	3,479
Changes in assets and liabilities:	'	'	'
Accounts receivable	-9,314	5,511	3,854
Accrued revenue	-50,156	-10,683	-11,118
Other current assets	19,543	-8,882	-4,528
Accounts payable	1,039	-2,117	-1,875
Accrued liabilities	26,803	14,790	17,124
Revenue distributions payable	50,552	11,268	4,852
Other	3,447	15,000	'
Net cash provided by operating activities	534,707	332,255	266,307
Cash flows from investing activities:	'	'	'
Additions to proved properties	-15,300	-10,254	-105,405
Additions to unproved properties	-440,825	-687,403	-195,131
Drilling and completion costs	-1,615,965	-836,350	-527,710
Additions to fresh water distribution systems	-203,790	-2,801	'
Additions to gathering systems and facilities	-389,453	-142,294	-72,837
Additions to other property and equipment	-6,240	-3,447	-2,339
(Increase) decrease in notes receivable	4,555	4,889	-10,111
Increase in other assets	-6,574	-3,707	-3,095
Proceeds from asset sales	'	1,217,876	15,379
Net cash used in investing activities	-2,673,592	-463,491	-901,249
Cash flows from financing activities:	'	'	'
Issuance of common stock	1,578,573	'	'
Issuance of senior notes	1,231,750	300,000	400,000
Repayment of senior notes	-690,000	'	'
Borrowings (repayments) on bank credit facility, net	71,000	-148,000	265,000
Payments of deferred financing costs and loss on extinguishment of debt	-53,940	-5,926	-6,691
Distribution to members	'	'	-28,859
Other	'	808	-153
Net cash provided by financing activities	2,137,383	146,882	629,297
Net increase (decrease) in cash and cash equivalents	-1,502	15,646	-5,645
Cash and cash equivalents, beginning of period	18,989	3,343	8,988
Cash and cash equivalents, end of period	17,487	18,989	3,343
Supplemental disclosure of cash flow information:	'	'	'
Cash paid during the period for interest	117,832	90,122	59,107
Supplemental disclosure of noncash investing activities:	'	'	'
Changes in accounts payable for additions to property and equipment	$188,123	$72,881	$26,465

Organization

Organization	12 Months Ended
	Dec. 31, 2013
Organization	'
Organization	'
	(1) Organization
	(a)   Business and Organization
	Antero Resources Corporation and its consolidated subsidiary (collectively referred to as the "Company," "we," or "our") are engaged in the exploitation, development, and acquisition of natural gas, natural gas liquids ("NGLs") and oil properties in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. We target large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. During 2012 we sold our Oklahoma Arkoma Basin properties and our Colorado Piceance Basin properties. We also have midstream gathering and water distribution operations in the Appalachian Basin. Our corporate headquarters are in Denver, Colorado.
	Our consolidated financial statements as of December 31, 2013 include the accounts of Antero Resources Corporation and its subsidiary, Antero Resources Midstream LLC.
	(b)   Corporate Reorganization and Initial Public Offering (IPO)
	Prior to October 16, 2013, the Company's predecessor, Antero Resources LLC, filed reports with the Securities and Exchange Commission. Antero Resources LLC was formed in October 2009 by members of the Company's management team and its sponsor investors. Antero Resources LLC owned 100% of the outstanding shares of Antero Resources Appalachian Corporation, which was formed in March 2008 and renamed Antero Resources Corporation in June 2013. In connection with our initial public offering ("IPO") completed on October 16, 2013, all of the ownership interests in Antero Resources LLC were exchanged for similar interests in a newly formed limited liability company, Antero Resources Investment LLC ("Antero Investment"), and Antero Resources LLC was merged into Antero Resources Corporation. As a result of this reorganization, Antero Investment owned 100% of the issued and outstanding 224,375,000 shares of common stock of Antero Resources Corporation prior to the IPO.
	On October 16, 2013, Antero Resources Corporation issued 37,674,659 additional shares of its common stock at $44.00 per share in an IPO resulting in proceeds to the Company, net of underwriter discounts and expenses of the offering, of approximately $1.6 billion. Antero Investment also sold 3,409,091 shares of its common stock of Antero Resources Corporation in the IPO. The Company did not receive any of the proceeds from the sale of the shares by Antero Investment.
	In 2013, the Company formed a subsidiary, Antero Resources Midstream LLC ("Antero Midstream"). The Company owns all of the membership interests in Antero Midstream other than a special membership interest which is indirectly owned by Antero Investment. In connection with an initial public offering of Antero Midstream during 2014, the Company intends to contribute its midstream assets to Antero Midstream and enter into commercial arrangements for midstream services. The assets to be contributed consist of (i) low- and high-pressure natural gas gathering lines, (ii) fresh water distribution systems and (iii) compression facilities. The special membership interest in Antero Midstream provides Antero Investment with certain rights, including the right to cause an initial public offering of Antero Midstream as a master limited partnership ("MLP") or similar structure. Following any such initial public offering, the special membership interest will entitle Antero Investment to the general partner interest in the MLP, which will allow Antero Investment to manage Antero Midstream's business and affairs. Following any such initial public offering, Antero Investment will also hold incentive distribution rights in the MLP, which will represent the right to receive an increasing percentage of the MLP's quarterly cash distributions in excess of specified target distribution levels.
	(c)   Stock Compensation Charge in Connection with the Reorganization
	In connection with the formation of Antero Resources LLC in October 2009, Antero Resources LLC issued profits interests to Antero Resources Employee Holdings LLC ("Employee Holdings"), which is owned solely by certain of our officers and employees. These profits interests provide for the participation in distributions upon liquidation events meeting certain requisite financial return thresholds. In turn, Employee Holdings issued membership interests to certain of our officers and employees. The Employee Holdings interests in Antero Resources LLC were exchanged for similar interests in Antero Investment on October 16, 2013.
	The limited liability company agreement of Antero Investment provides a mechanism by which the shares of the Company's common stock to be allocated among the members of Antero Investment, including Employee Holdings, will be determined. As a result of the adoption of the Antero Investment LLC agreement, the satisfaction of all performance and service conditions relative to the profits interests awards held by Employee Holdings in Antero Investment became probable. Accordingly, we recognized approximately $365 million of stock compensation expense for the vested profits interests through December 31, 2013 and will recognize an additional approximate $121 million over the remaining service period. Because consideration for the profits interests awards will be deemed given by Antero Investment, the charge to stock compensation expense is accounted for as a capital contribution by Antero Investment in the Company and credited to additional paid-in capital.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
Summary of Significant Accounting Policies	'
	(2) Summary of Significant Accounting Policies
	(a)   Basis of Presentation
	The accompanying consolidated financial statements include the accounts of Antero Resources Corporation and its subsidiary. All significant intercompany accounts and transactions have been eliminated.
	As of the date these financial statements were filed with the Securities and Exchange Commission, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.
	(b)   Use of Estimates
	The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.
	The Company's consolidated financial statements are based on a number of significant estimates including estimates of gas and oil reserve quantities, which are the basis for the calculation of depreciation, depletion, amortization, present value of cash flows from reserves, and impairment of oil and gas properties. Reserve estimates by their nature are inherently imprecise.
	(c)   Risks and Uncertainties
	Historically, the market for natural gas, NGLs, and oil has experienced significant price fluctuations. Prices for natural gas have been particularly volatile in recent years. The price fluctuations can result from variations in weather, levels of production in the region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in prices received could have a significant impact on the Company's future results of operations.
	(d)   Cash and Cash Equivalents
	The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
	(e)   Oil and Gas Properties
	The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, costs of productive wells, development dry holes, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The Company reviews exploration costs related to wells-in-progress at the end of each quarter and makes a determination based on known results of drilling at that time whether the costs should continue to be capitalized pending further well testing and results or charged to expense. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
	Unproved properties with significant acquisition costs are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Other unproved properties are assessed for impairment on an aggregate basis. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognizing any gain or loss until the cost has been recovered. Impairment of unproved properties for leases which have expired or are expected to expire was $11.1 million, $13.0 million, and $10.9 million for the years ended December 31, 2011, 2012, and 2013, respectively.
	The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that the carrying value of the properties may not be recoverable. When determining whether impairment has occurred, the Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company reduces the carrying amount of the properties to their estimated fair value. The factors used to determine fair value include estimates of proved reserves, future commodity prices, cash flow from commodity hedges, future production estimates, anticipated capital expenditures, and a commensurate discount rate. There were no impairments of proved natural gas properties during the years ended December 31, 2011, 2012, and 2013.
	At December 31, 2013, the Company did not have significant capitalized costs related to exploratory wells-in-progress which were pending determination of proved reserves. The Company had no significant costs which have been deferred for longer than one year pending proved reserves at December 31, 2013.
	The provision for depreciation, depletion, and amortization of oil and gas properties is calculated on a geological reservoir basis using the units-of-production method. Depreciation, depletion, and amortization expense for oil and gas properties was $164.0 million, $181.7 million, and $219.8 million for the years ended December 31, 2011, 2012, and 2013, respectively.
	(f)    Gathering Pipelines, Compressor Stations, and Fresh Water Distribution Systems
	Gathering pipelines and compressor stations are depreciated using the straight-line method over their estimated useful life of 20 years. Fresh water distribution systems are depreciated over useful lives of from 5 to 20 years. Expenditures for installation, major additions, and improvements are capitalized, and minor replacements, maintenance, and repairs are charged to expenses as incurred. For the years ended December 31, 2011, 2012, and 2013, depreciation expense for gathering pipelines, compressor stations, and fresh water distribution systems was $5.5 million, $7.4 million, and $11.9 million, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.
	(g)   Impairment of Long-Lived Assets Other than Oil and Gas Properties
	The Company evaluates its long-lived assets other than natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amount of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the unit being assessed. If the carrying value amounts of the assets are deemed to be not recoverable, the carrying amount is reduced to the estimated fair value, which is based on discounted future cash flows or other techniques, as appropriate. No impairments for such assets have been recorded through December 31, 2013.
	(h)   Other Property and Equipment
	Other property and equipment is depreciated using the straight-line method over estimated useful lives ranging from three to five years. For the years ended December 31, 2011, 2012, and 2013, depreciation expense for other property and equipment was $1.0 million, $1.7 million, and $2.2 million, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.
	(i)    Deferred Financing Costs
	Deferred financing costs represent loan origination fees, initial purchasers' discounts, and other borrowing costs and are included in noncurrent other assets on the consolidated balance sheets. These costs are being amortized over the term of the related debt using the effective interest method. The Company charges interest expense for deferred financing costs remaining for debt facilities that have been retired prior to their maturity date. At December 31, 2013, the Company had $28 million of unamortized deferred financing costs included in other long-term assets. The amounts amortized and the write-off of previously deferred debt issuance costs were $3.8 million, $5.2 million, and $15.8 million for the years ended December 31, 2011, 2012, and 2013, respectively.
	(j)    Derivative Financial Instruments
	In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position.
	The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues, and changes in the fair value of interest rate derivatives are classified as other income (expense).
	(k)   Asset Retirement Obligations
	The Company is obligated to dispose of certain long-lived assets upon their abandonment. The Company's asset retirement obligations (ARO) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their life. The ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company's credit-adjusted, risk-free interest rate. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation and interest rates, and changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.
	The Company delivers natural gas through its gathering assets and delivers water through its water distribution assets and may become obligated by regulatory or other requirements to remove certain facilities or perform other remediation upon retirement of gathering pipelines and compressor stations. However, the Company cannot reasonably predict when production from existing reserves of the fields in which we operate will cease. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates will occur and therefore have not recorded asset retirement obligations related to gathering assets.
	(l)    Environmental Liabilities
	Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable, and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2012 and 2013, the Company has not accrued a material amount for any environmental liabilities nor has it been fined or cited for any environmental violations that could have a material adverse effect on future capital expenditures or operating results of the Company.
	(m)  Natural Gas, NGL and Oil Revenues
	Sales of natural gas, NGLs, and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one month after the sale has occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a revenue distribution payable to the extent it receives more than its proportionate share natural gas revenues. At December 31, 2012 and 2013, the Company had no significant imbalance positions.
	(n)   Concentrations of Credit Risk
	The Company's revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry. The concentration of credit risk in a single industry affects the Company's overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables.
	The Company's sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2011, 2012, and 2013 are as follows (including sales in discontinued operations):
		2011			2012			2013
	Company A		28	%		23	%		30	%
	Company B		17			13			14
	Company C		12			10			8
	All others		43			54			48
			100	%		100	%		100	%
	Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.
	The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations. The fair value of our commodity derivative contracts of approximately $860 million at December 31, 2013 includes the following values by bank counterparty: BNP Paribas—$197 million; Credit Suisse—$190 million; Barclays—$147 million; Wells Fargo—$140 million; JP Morgan—$134 million; Citigroup—$34 million; Deutsche Bank—$15 million; and Toronto Dominion Bank—$3 million. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates at December 31, 2013 for each of the European and American banks. We believe that all of these institutions currently are acceptable credit risks.
	The Company, at times, may have cash in banks in excess of federally insured amounts.
	(o)   Income Taxes
	The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance, when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
	Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties as income tax expense.
	(p)   Fair Value Measures
	FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties, and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include nonexchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, and interest rate swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.
	(q)   Industry Segment and Geographic Information
	We have evaluated how the Company is organized and managed and have identified the following operating segments: (1) the exploration and production of oil, natural gas, and natural gas liquids, and (2) midstream operations consisting of natural gas gathering, compression, and fresh water distribution operations for the distribution of fresh water used in well completions. Prior to 2013, the Company did not have any reportable segments and considered its gathering, compression, and fresh water distribution operations to be ancillary to its exploration and production activities. In connection with the proposed initial public offering of Antero Midstream, the Company intends to contribute its midstream assets to Antero Midstream. Antero Midstream is expected to enter into agreements with the Company for the dedication of substantially all of the Company's current and future acreage for natural gas gathering and compression services and for fresh water sourcing and delivery related to all of the Company's current and future drilling. The Company intends to convert Antero Midstream into a limited partnership in connection with a public offering of Antero Midstream as a master limited partnership. As a result of these transactions, management has begun to evaluate these gathering and compression and fresh water distribution services separately from exploration and production activities and these operations therefore became reportable segments as of December 31, 2013. Prior to 2013 and the planned master limited partnership, gathering and compression and fresh water distribution services were not material.
	All of our assets are located in the United States and all of our revenues are attributable to customers located in the United States.
	(r)   Reclassifications
	Certain reclassifications have been made to prior periods' financial information related to water distribution assets to conform to the 2013 presentation.
	(s)   Earnings (loss) per share.
	Earnings (loss) per common share and earnings (loss) per common share—assuming dilution for each of the three years ended December 31, 2013 was calculated as if the shares issued in the Corporate Reorganization and IPO described in Note 1 were outstanding for the entire period. The effect of dilutive options and restricted stock awards in 2013 is less than $0.01 per share.

Sale_of_Piceance_and_Arkoma_Pr

Sale of Piceance and Arkoma Properties - Discontinued Operations (Piceance Basin and Arkoma Basin)	12 Months Ended
	Dec. 31, 2013
Piceance Basin and Arkoma Basin	'
Sale of Assets	'
Sale of Piceance and Arkoma Properties - Discontinued Operations	'
	(3) Sale of Piceance and Arkoma Properties—Discontinued Operations
	On December 21, 2012 the Company completed the sale of its Piceance Basin assets in Colorado. Proceeds from the sale of $316 million represent the purchase price of $325 million, adjusted for expenses of the sale and estimated income, expenses, and capital costs related to the Piceance Basin properties from the October 1, 2012 effective date of the sale through December 21, 2012 (the interim period). The purchaser also assumed all of the Company's Rocky Mountain firm transportation obligations. Because of the sale of the Piceance Basin assets, the Company also liquidated its hedge positions related to the Piceance Basin and realized additional proceeds from these transactions of approximately $100 million. The loss on the sale of the Piceance Basin assets was adjusted downward by $8.5 million in 2013 as a result of the resolution of certain liabilities recorded at the time of the sale and the settlement of final purchase price adjustments.
	On June 29, 2012 the Company completed its sale of its Arkoma Basin assets in Oklahoma and the commodity hedges associated with the Arkoma assets. Proceeds from the sale of $427 million represent the purchase price of $445 million adjusted for expenses of the sale and estimated income, expenses, and capital costs from the effective date of the sale through the closing date of June 29, 2012. The Company recorded a loss of $432 million on the sale of the Arkoma Basin assets. The Company's Arkoma Basin midstream operations, which were sold on November 5, 2010, are also included in discontinued operations through the date of the sale. The Company realized a gain in 2010 of $148 million on the sale of those midstream operations.
	Results of operations and the loss on the sale of the Piceance Basin and Arkoma Basin assets are shown as discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss) and are comprised of the following (in thousands):
		Year ended December 31
		2011			2012			2013
	Sales of oil, natural gas, and natural gas liquids	$	196,705		$	125,396		$	—
	Commodity derivative fair value gains		180,130			46,358			—
	Total revenues		376,835			171,754			—
	Lease operating		26,037			19,901			—
	Gathering, compression, and transportation		50,453			45,089			—
	Production taxes		6,307			2,967			—
	Exploration		5,842			664			—
	Impairment of unproved properties		6,387			962			—
	Depletion, depreciation, and amortization		114,805			88,720			—
	Accretion of asset retirement obligations		359			404			—
	Loss on sale of assets		—			795,945			(8,506	)
	Total expenses		210,190			954,652			(8,506	)
	Income (loss) from discontinued operations before income taxes		166,645			(782,898	)		8,506
	Income tax (expense) benefit		(45,155	)		272,553			(3,249	)
	Net income (loss) from discontinued operations	$	121,490		$	(510,345	)	$	5,257

Sale_of_Appalachian_Gathering_

Sale of Appalachian Gathering Assets (Appalachian Gathering Assets)	12 Months Ended
	Dec. 31, 2013
Appalachian Gathering Assets	'
Sale of Assets	'
Sale of Appalachian Gathering Assets	'
	(4) Sale of Appalachian Gathering Assets
	On March 26, 2012, the Company closed the sale of a portion of its Marcellus Shale gathering system assets in West Virginia along with exclusive rights to gather the Company's gas for a 20-year period within an area of dedication (AOD) to a joint venture owned by Crestwood Midstream Partners and Crestwood Holdings Partners LLC (together Crestwood) for $375 million (subject to customary purchase price adjustments). The sale included approximately 25 miles of low pressure pipeline systems and gathering rights on 104,000 net acres held by the Company within a 250,000 acre AOD and had an effective date of January 1, 2012. Other third-party producers will also have access to the Crestwood system. During the first seven years of the contract, the Company is committed to deliver minimum annual volumes into the gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies. The Company can earn up to an additional $40 million of sale proceeds over the next three years if it meets certain volume thresholds, but has not recorded any part of these contingent proceeds at December 31, 2013. Crestwood is obligated to incur all future capital costs to build out gathering systems and compression facilities within the AOD to connect the Company's wells as it executes its drilling program and has assumed the various risks and rewards of the system build-out and operations. Because the Company has not retained the substantial risks and rewards of ownership associated with the gathering rights and systems transferred to Crestwood, it has recognized a gain on the sale of the gathering system and gathering rights of approximately $291 million.

Notes_Receivable

Notes Receivable	12 Months Ended
	Dec. 31, 2013
Notes Receivable	'
Notes Receivable	'
	(5) Notes Receivable
	At December 31, 2012 and 2013 the Company had notes receivable from a drilling contractor of $7.2 million and $2.7 million, respectively. The notes result from the Company's advances to the drilling contractor to construct drilling rigs to be used by the contractor to fulfill long-term drilling contracts with the Company. The notes are noninterest bearing and are repayable over the term of the service agreements with the drilling contractor.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2013
Long-Term Debt	'
Long-Term Debt	'
	(6) Long-Term Debt
	The Company's had long-term debt as follows at December 31, 2012 and 2013 (in thousands):
		2012		2013
	Bank credit facility(a)	$	217,000	$	288,000
	9.375% senior notes due 2017(b)		525,000		—
	7.25% senior notes due 2019(c)		400,000		260,000
	6.00% senior notes due 2020(d)		300,000		525,000
	5.375% senior notes due 2021(e)		—		1,000,000
	9.00% senior note due 2013(f)		25,000		—
	Net unamortized premium		2,058		5,999
			1,469,058		2,078,999
	Less amounts due within one year		25,000		—
		$	1,444,058	$	2,078,999
	(a)   Senior Secured Revolving Credit Facility
	The Company has a senior secured revolving bank credit facility (the Credit Facility) with a consortium of bank lenders. The maximum amount of the Credit Facility is $2.5 billion. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved properties and commodity hedge positions and are subject to regular semiannual redeterminations. At December 31, 2013, the borrowing base was $2.0 billion and lender commitments were $1.5 billion. Lender commitments can be increased to the full amount of the borrowing base upon approval of the lending group. The next redetermination of the borrowing base is scheduled to occur in April 2014. The Credit Facility matures on May 12, 2016.
	The Credit Facility is secured by mortgages on substantially all of the Company's properties and guarantees from the Company's subsidiary. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company's election at the time of borrowing. The Company was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2012 and 2013.
	As of December 31, 2013, the Company had an outstanding balance under the Credit Facility of $288 million, with a weighted average interest rate of 1.61%, and outstanding letters of credit of $32 million. As of December 31, 2012, the Company had an outstanding balance under the Credit Facility of $217 million, with a weighted average interest rate of 1.91%, and outstanding letters of credit of approximately $43 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization.
	(b)   Redemption of 9.375% Senior Notes
	On December 2, 2013, the Company redeemed the 9.375% senior notes due in 2017 out of the proceeds from the issuance of the 5.375% senior notes due 2021. The notes were redeemed at a price of 104.688% and the resulting premium of $24.6 million was charged to Loss on Early Extinguishment of Debt, which is included in Other Expenses in the accompanying Statement of Operations. Additionally, $5.9 million of deferred financing costs, net of unamortized premium, was charged to Loss on Early Extinguishment of Debt.
	(c)   7.25% Senior Notes Due 2019
	On August 1, 2011, the Company issued $400 million of 7.25% senior notes due August 1, 2019 at par. The notes are unsecured and effectively subordinated to the Company's Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a senior unsecured basis by Antero Midstream, Antero Resources Midstream Operating ("Midstream Operating") and certain of our future restricted subsidiaries. Interest on the notes is payable on August 1 and February 1 of each year. The Company may redeem all or part of the notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017. At any time prior to August 1, 2014, the Company may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a "make-whole" premium and accrued interest. If the Company undergoes a change of control, the note holders will have the right to require the Company to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.
	On November 25, 2013, the Company redeemed $140 million of the 7.25% senior notes out of the proceeds from the public stock offering completed on October 16, 2013. The notes were redeemed at a price of 107.25% and the resulting premium of $10.2 million was charged to Loss on Early Extinguishment of Debt, which is included in Other Expense in the accompanying Statement of Operations. Additionally, $1.9 million of deferred financing costs was charged to Loss on Early Extinguishment of Debt.
	(d)   6.00% Senior Notes Due 2020
	On November 19, 2012, the Company issued $300 million of 6.00% senior notes due December 1, 2020 at par. After December 31, 2012, on February 4, 2013 the Company issued an additional $225 million of the 6.00% notes at 103% of par. The notes are unsecured and effectively subordinated to the Company's Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 5.375% and 7.25% senior notes. The notes are guaranteed on a senior unsecured basis by Antero Midstream, Midstream Operating and certain of our future restricted subsidiaries. Interest on the notes is payable on June 1 and December 1 of each year, commencing on June 1, 2013. The Company may redeem all or part of the notes at any time on or after December 1, 2015 at redemption prices ranging from 104.500% on or after December 1, 2015 to 100.00% on or after December 1, 2018. In addition, on or before December 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 106.00% of the principal amount of the notes, plus accrued interest. At any time prior to December 1, 2015, the Company may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a "make-whole" premium and accrued interest. If a change of control (as defined in the bond indenture) occurs at any time prior to January 1, 2014, the Company may, at its option, redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the notes, plus accrued interest. If the Company undergoes a change of control, the note holders will have the right to require the Company to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.
	(e)   5.375% Senior Notes Due 2021
	On November 5, 2013, the Company issued $1 billion of 5.375% senior notes due November 21, 2021 at par. The notes are unsecured and effectively subordinated to the Company's Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a full and unconditional and joint and several basis by Antero Midstream, Midstream Operating and certain of our future restricted subsidiaries. Interest on the notes is payable on May 1 and November 1 of each year. The Company may redeem all or part of the notes at any time on or after November 1, 2016 at redemption prices ranging from 104.031% on or after November 1, 2016 to 100.00% on or after November 1, 2019. At any time prior to November 1, 2016, the Company may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a "make-whole" premium. If the Company undergoes a change of control, it may be required to offer to purchase notes from the holders. There are no restrictions on the Company's ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.
	(f)    9.00% Senior Note
	The Company assumed a $25 million unsecured 9% note payable in the business acquisition consummated on December 1, 2010. The note was repaid on December 1, 2013.
	(g)   Treasury Management Facility
	The Company has a stand-alone revolving note with a lender under the Credit Facility which provides for up to $25.0 million of cash management obligations in order to facilitate the Company's daily treasury management. Borrowings under the revolving note are secured by the collateral for the revolving credit facility. Borrowings under the facility bear interest at the lender's prime rate plus 1.0%. The note matures on June 1, 2014. At December 31, 2013, there were no outstanding borrowings under this facility.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
Asset Retirement Obligations	'
	(7) Asset Retirement Obligations
	The following is a reconciliation of the Company's asset retirement obligations for the years ended December 31, 2012 and 2013 (in thousands).
		2012			2013
	Asset retirement obligations—beginning of year	$	6,715		$	10,552
	Obligations incurred for wells drilled or on properties acquired		9,440			242
	Obligations related to assets sold		(6,107	)		—
	Accretion expense		504			1,065
	Asset retirement obligations—end of year	$	10,552		$	11,859

Profits_Interests_Awards

Profits Interests Awards	12 Months Ended
	Dec. 31, 2013
Profits Interests Awards	'
Profits Interests Awards	'
	(8) Profits Interests Awards
	Employee Holdings, a limited liability company owned by officers and employees, has issued profits interests to employees. The profits interests participate only in distributions from Antero Investment in liquidity events, meeting requisite financial thresholds after the Class I and other classes of unitholders have recovered their investment and special allocation amounts. The profits interests have no voting rights. As described in note 1, the limited liability company agreement of Antero Investment executed at the closing of the IPO provides a mechanism by which the shares of the Company's common stock to be allocated among the members of Antero Investment, including Employee Holdings, will be determined. As a result, the satisfaction of all performance and service conditions relative to the profits interests awards held by Employee Holdings in Antero Investment became probable. Accordingly, we recognized approximately $365 million of stock compensation expense for the vested profits interests through December 31, 2013 and will recognize an additional approximate $121 million over the remaining service period. All available profits interest awards were made prior to the date of the IPO and no additional awards will be made.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2013
Stock-Based Compensation	'
Stock-Based Compensation	'
	(9) Stock-Based Compensation
	The Company is authorized to grant up to 16,906,500 stock-based compensation awards to employees and directors of the Company under the Antero Resources Corporation Long-Term Incentive Plan (the Plan). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company's Board of Directors. A total of 16,791,068 shares are available for future grant under the Plan as of December 31, 2013.
	Our stock-based compensation expense is as follows for the year ended December 31, 2013 (in thousands):
	Profits interests awards (see note 8)	$	364,957
	Restricted stock		219
	Stock options		104
	Total expense	$	365,280
	Restricted Stock Awards
	Restricted stock awards vest subject to the satisfaction of service requirements. The grant date fair value of these awards are determined based on the price of the Company's common stock on the date of the grant. A summary of restricted stock awards activity during the year ended December 31, 2013 is as follows:
		Number of			Weighted		Aggregate
		shares			average		intrinsic value
					grant date		(in thousands)
					fair value
	Total granted and unvested, January 1, 2013		—			—		—
	Granted		45,093		$	54.27
	Vested		—
	Forfeited		—
	Total awarded and unvested—December 31, 2013		45,093		$	54.27	$	2,861
	The outstanding unvested restricted stock awards at December 31, 2013 are scheduled to vest as follows:
	Vesting date	Number of
		awards
	2014		20,818
	2015		8,092
	2016		8,092
	2017		8,091
	Stock Options
	Stock options granted under the Plan to date vest over periods from one to four years and have a maximum contractual life of 10 years. We recognize expense related to stock options on a straight-line basis over the requisite service period, less awards expected to be forfeited. Stock options are granted with an exercise price equal to the market price of our common stock on the date of grant. A summary of stock option activity for the year ended December 31, 2013 is as follows:
		Stock options			Weighted		Weighted		Intrinsic
					average		average		value
					exercise		remaining		(in thousands)
					price		contractual
							life
	Outstanding at January 1, 2013		—			—		—		—
	Options granted		70,339		$	54.15
	Options exercised		—			—
	Options cancelled		—			—
	Options expired		—			—
	Outstanding at December 31, 2013		70,339		$	54.15
	Vested or expected to vest as of December 31, 2013		70,339		$	54.15		9.79	$	653
	Exercisable at December 31, 2013		—					9.79	$	653
	We use a Black-Scholes option-pricing model to determine the fair value of our stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies' stock prices. The risk-free interest rate was determined using the implied yield currently available for zero-coupon U.S. government issues with a remaining term approximating the expected life of the options. We assumed no dividend yield.
	The following table presents information regarding the weighted average fair value for options granted during 2013 and the assumptions used to determine fair value. There were no options exercised during 2013.
	Dividend yield		—	%
	Volatility		35	%
	Risk-free interest rate		1.48	%
	Expected life (years)		6.17
	Weighted average fair value of options granted	$	20.2
	As of December 31, 2013, there was $1.3 million of unrecognized stock-based compensation expense related to nonvested stock options. That expense is expected to be recognized over a weighted average period of 4 years.

Financial_Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2013
Financial Instruments	'
Financial Instruments	'
	(10) Financial Instruments
	The carrying values of trade receivables and trade payables at December 31, 2012 and 2013 approximated market value because of their short-term nature. The carrying value of the bank credit facility at December 31, 2012 and 2013 approximated fair value because the variable interest rates are reflective of current market conditions.
	The fair value of the Company's senior notes was approximately $1.9 billion, based on Level 2 market data inputs at December 31, 2013.
	See (note 11) for information regarding the fair value of derivative financial instruments.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments	'
Derivative Instruments	'
	(11) Derivative Instruments
	(a)   Commodity Derivatives
	The Company periodically enters into natural gas derivative contracts with counterparties to hedge the price risk associated with a portion of its production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas recognized upon the ultimate sale of the natural gas produced.
	For the years ended December 31, 2011, 2012, and 2013, the Company was party to natural gas fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price the Company receives the difference from the counterparty. The Company's natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.
	As of December 31, 2013, the Company has entered into fixed price natural gas and oil swaps in order to hedge a portion of its natural gas and oil production from January 1, 2014 through December 31, 2019 as summarized in the following table.
		Natural gas			Oil			Weighted
		MMbtu/day			Bbls/day			average index
								price
	Year ending December 31, 2014:
	CGTAP-TCO		210,000			—		$	5.11
	Dominion South		160,000			—			5.15
	NYMEX		230,000			—			3.99
	CGLA		10,000			—			3.87
	NYMEX-WTI		—			3,000			96.53
	2014 Total		610,000			3,000
	Year ending December 31, 2015:
	CGTAP-TCO		130,000					$	4.93
	Dominion South		230,000						5.6
	NYMEX		140,000						4.08
	CGLA		40,000						4
	2015 Total		540,000
	Year ending December 31, 2016:
	CGTAP-TCO		80,000					$	4.67
	Dominion South		272,500						5.35
	NYMEX		110,000						4.18
	CGLA		170,000						4.09
	2016 Total		632,500
	Year ending December 31, 2017:
	CGTAP-TCO		20,000					$	4.02
	NYMEX		230,000						4.43
	CGLA		420,000						4.27
	CCG		70,000						4.57
	2017 Total		740,000
	Year ending December 31, 2018:
	NYMEX		620,000					$	4.66
	Year ending December 31, 2019:
	CGLA		277,500					$	4.51
	(b)   Interest Rate Derivatives
	In the past, the Company has entered into various floating-to-fixed interest rate swap derivative contracts to manage exposures to changes in interest rates from variable rate obligations. Under the swaps, the Company made payments to the swap counterparty when the variable LIBOR three-month rate fell below the fixed rate or received payments from the swap counterparty when the variable LIBOR three-month rate went above the fixed rate. The Company had no outstanding interest rate swap agreements at December 31, 2012 and 2013.
	(c)   Summary
	The following is a summary of the fair values of derivative instruments not designated as hedges for accounting purposes and where such values are recorded in the consolidated balance sheets as of December 31, 2012 and 2013. None of the Company's derivative instruments are designated as hedges for accounting purposes.
		2012					2013
		Balance sheet		Fair value			Balance sheet		Fair value
		location					location
				(In thousands)					(In thousands)
	Asset derivatives not designated as hedges for accounting purposes:
	Commodity contracts	Current assets		$	160,579		Current assets		$	183,000
	Commodity contracts	Long-term assets			371,436		Long-term assets			677,780
	Total asset derivatives			$	532,015				$	860,780
	Liability derivatives not designated as hedges for accounting purposes:
	Commodity contracts	Current liabilities			—					646
	Net derivatives			$	532,015				$	860,134
	The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value (in thousands):
											December 31, 2013
		December 31, 2012
																Net amounts
																of assets
																(liabilities)
																on balance
		Gross amounts			Gross amounts			Net amounts			Gross amounts		Gross amounts			sheet
		of recognized			offset on			of assets			of recognized		offset on
		assets			balance sheet			on balance			assets		balance sheet
								sheet
Commodity derivative assets	$	597,359		$	(65,344	)	$	532,015		$	887,034	$	(26,254	)	$	860,780
Commodity derivative liabilities		—			—			—			—		(646	)		(646	)
The following is a summary of derivative fair value gains (losses) and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2011, 2012, and 2013 (in thousands):
	Statement of operations		2011			2012			2013
	location
Commodity derivative fair value gains	Revenue		$	496,064		$	179,546		$	491,689
Commodity derivative fair value gains	Discontinued operations			180,130			46,358			—
Total commodity derivative fair value gains				676,194			225,904			491,689
Interest rate derivative fair value losses	Other expenses			(94	)		—			—
Net derivative fair value gains			$	676,100		$	225,904		$	491,689
The fair value of commodity and interest rate derivative instruments was determined using Level 2 inputs.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
Income Taxes	'
	(12) Income Taxes
	For the years ended December 31, 2011, 2012, and 2013 income tax expense from continuing operations consisted of the following (in thousands):
		2011			2012			2013
	Current income tax expense (benefit)	$	—		$	15,000		$	(4,000	)
	Deferred income tax expense		185,297			106,229			190,210
	Total income tax expense from continuing operations	$	185,297		$	121,229		$	186,210
	The income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to consolidated income for the years ended December 31, 2011, 2012, and 2013, as a result of the following (in thousands):
		2011			2012			2013
	Federal income tax expense	$	159,770		$	121,276		$	56,708
	State income tax expense, net of federal benefit		23,593			4,761			21,429
	Nondeductible stock compensation		—			—			127,736
	Change in valuation allowance		(934	)		(4,872	)		(20,919	)
	Other		2,868			64			1,256
	Total income tax expense from continuing operations	$	185,297			121,229			186,210
	For the years ended December 31, 2011, 2012, and 2013 income tax expense (benefit) was allocated to continuing and discontinued operations as follows (in thousands):
		2011			2012			2013
	Continuing operations	$	185,297		$	121,229		$	186,210
	Discontinued operations and sale of discontinued operations		45,155			(272,553	)		3,249
	Total income tax expense (benefit)	$	230,452		$	(151,324	)	$	189,459
	Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities at December 31, 2012 and 2013 is as follows (in thousands):
		2012			2013
	Deferred tax assets:
	Net operating loss carryforwards	$	417,385		$	449,961
	Capital loss carryforwards		5,367			—
	Minimum tax credit carryforward		15,000			11,000
	Other		5,006			5,373
	Total deferred tax assets		442,758			466,334
	Valuation allowance		(47,678	)		(26,759	)
	Net deferred tax assets		395,080			439,575
	Deferred tax liabilities:
	Unrealized gains on derivative instruments		206,937			328,534
	Oil and gas properties		342,455			458,812
	Total deferred tax liabilities		549,392			787,346
	Net deferred tax liabilities	$	(154,312	)	$	(347,771	)
	In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of all of these deductible differences and has recorded a valuation allowance of approximately $48 million and $27 million at December 31, 2012 and 2013, respectively, which is primarily related to capital loss carryforwards and certain state NOL carryforwards related to states where we no longer operate. The amount of the deferred tax asset considered realizable could be reduced in the near term if estimates of future taxable income during the carryforward period are revised.
	The calculation of the Company's tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The financial statements include unrecognized benefits at December 31, 2013 of $11 million that, if recognized, would result in a reduction of noncurrent income taxes payable (included in other long-term liabilities) and an increase in noncurrent deferred tax liabilities. No impact to the Company's 2013 effective tax rate would result. As of December 31, 2013, interest of $0.5 million has been accrued on unrecognized tax benefits. A reconciliation of beginning and ending amount of unrecognized tax benefits is as follows:
		2013
	Balance at beginning of year	$	15,000
	Revised estimate of unrecognized tax position		(4,000	)
	Balance at end of year	$	11,000
	The Company's corporate subsidiaries have U.S. Federal and state net operating loss carryforwards (NOLs) as of December 31, 2013 of $1.2 billion and $1.1 billion, respectively, which expire at various dates from 2024 to 2033.
	The tax years 2010 through 2013 remain open to examination by the U.S. Internal Revenue Service. The Company and subsidiaries file tax returns with various state taxing authorities; these returns remain open to examination for tax years 2009 through 2013. The tax returns of Antero Resources Finance Corporation (which was merged with the Antero Resources Corporation in December 2013) are being examined by the Internal Revenue Service for its tax years 2011 and 2012. The Company's state tax returns are being examined by West Virginia taxing authorities for tax years 2010 through 2012. The Company does not expect any material adjustments to tax liabilities will result from either the federal or the state examination.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2013
Commitments	'
Commitments	'
	(13) Commitments
	The following is a schedule of future minimum payments for firm transportation agreements, drilling and compression facility obligations, and leases that have remaining lease terms in excess of one year as of December 31, 2013 (in millions).
		Firm		Gas processing,		Drilling rigs		Office and		Total
		transportation		gathering and		and frac		equipment
		(a)		compression		Services		(d)
				(b)		(c)
	Year ending December 31:
	2014	$	120.5	$	182.8	$	150.9	$	3.9	$	458.1
	2015		159.5		184.7		68.3		4.1		416.6
	2016		160.9		196.1		13.7		3.8		374.5
	2017		158.4		192.5		—		3.2		354.1
	2018		159		189.1		—		1.5		349.6
	Thereafter		1,002.90		836.1		—		14.1		1,853.10
	Total	$	1,761.20	$	1,781.30	$	232.9	$	30.6	$	3,806.00
	(a)   Firm Transportation
	The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes or ethane at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent our minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that we are committed to pay; however, the Company will record in our financial statements our proportionate share of costs based on our working interest.
	(b)   Gas Processing and Compression Service Commitments
	The Company has entered into various long-term gas processing agreements for certain of its production that will allow us to realize the value of our NGLs. The minimum payment obligations under the agreements are presented in the table.
	The Company has various compressor service agreements with third parties that provide for payments based on volumes compressed and have minimum payment obligations which are presented in the table.
	The values in the table represent the gross amounts that we are committed to pay; however, the Company will record in our financial statements our proportionate share of costs based on our working interest.
	(c)   Drilling Rig Service Commitments
	The Company has obligations under agreements with service providers to procure drilling rigs and compression and frac services. At December 31, 2013, the Company had contracts for the services of 20 rigs. The contracts expire at various dates from March 2014 through November 2016. The values in the table represent the gross amounts that we are committed to pay; however, the Company will record in our financial statements our proportionate share of costs based on our working interest.
	(d)   Office and Equipment Leases
	The Company leases various office space and equipment under operating lease arrangements. Rental expense under operating leases is included in general and administrative expenses and was $1.0 million, $1.1million, and $1.8 million for the years ended December 31, 2011, 2012, and 2013, respectively.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2013
Contingencies	'
Contingencies	'
	(14) Contingencies
	The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Information	'
Segment Information	'
	(15) Segment Information
	See note 1 for a description of the Company's determination of its reportable segments for 2013. Prior to 2013, midstream gathering and water distribution operations were immaterial and were considered ancillary to the Company's exploration and production activities. The operating results and assets of the Company's reportable segments were as follows for 2013 (in thousands):
		Exploration and		Gathering and		Fresh water		Elimination of			Consolidated
		production		compression		distribution		intersegment			total
								transactions
	2013:00:00
	Sales and revenues:
	Third-party	$	1,313,134		—		—		—			1,313,134
	Intersegment		—		22,363		35,871		(58,234	)		—
		$	1,313,134		22,363		35,871		(58,234	)		1,313,134
	Depiction, depreciation, and amortization	$	220,857		11,346		2,773		(1,100	)		233,876
	Interest expense	$	136,453		155		9		—			136,617
	Income tax expense	$	186,210		—		—		—			186,210
	Operating income(1)	$	335,901		8,938		27,296		(30,928	)		341,207
	Segment assets	$	6,580,282		561,855		230,247		(758,803	)		6,613,581
	Capital expenditures for	$	2,110,358		389,453		203,790		(32,028	)		2,671,573
	segment assets
	-1
	All general and administrative expenses are included in the exploration and production segment.

Subsidiary_Guarantor

Subsidiary Guarantor	12 Months Ended
	Dec. 31, 2013
Subsidiary Guarantor	'
Subsidiary Guarantor	'
	(16) Subsidiary Guarantor
	Antero Resources Corporation (the parent) and its wholly owned subsidiary each have fully and unconditionally guaranteed the Company's senior notes. The following Condensed Consolidating Balance Sheet at December 31, 2013, as of December 31, 2013, present financial information for Antero Resources Corporation as the Parent on a stand-alone basis (carrying its investment in subsidiary on the equity method), financial information for the subsidiary guarantor (Antero Resources Midstream LLC), and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. The guarantor subsidiary had no revenues, expenses, or cash flow during the year ended December 31, 2013. The subsidiary is not restricted from making distributions to the Company.
	Condensed Consolidating Balance Sheets
	December 31, 2013
	(In thousands)
		Parent		Guarantor		Eliminations			Consolidated
				Subsidiary
	Assets
	Current assets:
	Cash and cash equivalents	$	17,487	$	—	$	—		$	17,487
	Other		316,077		1		(1	)		316,077
	Total current assets		333,564		1		(1	)		333,564
	Property and equipment, net		5,559,656		—		—			5,559,656
	Other long-term assets		720,361		—		—			720,361
	Investment in subsidiary		1		—		(1	)		—
		$	6,613,582	$	1	$	(2	)	$	6,613,581
	Liabilities and Stockholders' Equity
	Current liabilities	$	622,229	$	—	$			$	622,229
	Long-term debt		2,078,999		—		—			2,078,999
	Other long-term liabilities		313,693		—		—			313,693
	Due to subsidiary		1		—		(1	)		—
	Total liabilities		3,014,922		—		(1	)		3,014,921
	Stockholders' or member's equity		3,598,660		1		(1	)		3,598,660
	Total liabilities and equity	$	6,613,582	$	1	$	(2	)	$	6,613,581

Quarterly_Financial_Informatio

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information (Unaudited)	'
Quarterly Financial Information (Unaudited)	'
	(17) Quarterly Financial Information (Unaudited)
	The Company's quarterly financial information for the years ended December 31, 2012 and 2013 is as follows (in thousands, except per share amounts):
		First			Second			Third			Fourth
		quarter			quarter			quarter			quarter
	Year ended December 31, 2012:
	Total operating revenues	$	553,741		$	38,925		$	(92,038	)	$	235,090
	Total operating expenses		43,405			62,381			74,840			111,077
	Operating income (loss)		510,336			(23,456	)		(166,878	)		124,013
	Income (loss) from continuing operations		287,555			(33,237	)		(113,887	)		84,845
	Income (loss) from discontinued operations		40,176			(444,850	)		(13,791	)		(91,880	)
	Net income (loss)		327,731			(478,087	)		(127,678	)		(7,035	)
	Earnings (loss) per common share—basic:
	Continuing operations	$	1.1		$	(0.12	)	$	(0.44	)	$	0.32
	Discontinued operations		0.15			(1.70	)		(0.05	)		(0.35	)
	Net income (loss)	$	1.25		$	(1.82	)	$	(0.49	)	$	(0.03	)
	Earnings (loss) per common share—diluted:
	Continuing operations	$	1.1		$	(0.12	)	$	(0.44	)	$	0.32
	Discontinued operations		0.15			(1.70	)		(0.05	)		(0.35	)
	Net income (loss)	$	1.25		$	(1.82	)	$	(0.49	)	$	(0.03	)
		First			Second			Third			Fourth
		quarter			quarter			quarter			quarter
	Year Ended December 31, 2013:
	Total operating revenues	$	61,454		$	387,144		$	384,522		$	480,014
	Total operating expenses		109,923			138,758			161,914			561,332
	Operating income (loss)		(48,469	)		248,386			222,608			(81,318	)
	Income (loss) from continuing operations		(47,997	)		131,193			117,794			(225,177	)
	Income (loss) from discontinued operations		—			—			3,100			2,157
	Net income (loss)		(47,997	)		131,193			120,894			(223,020	)
	Earnings (loss) per common share—basic:
	Continuing operations	$	(0.18	)	$	0.5		$	0.45		$	(0.86	)
	Discontinued operations		—			—			0.01			0.01
	Net income (loss)	$	(0.18	)	$	0.5		$	0.46		$	(0.85	)
	Earnings (loss) per common share—diluted:
	Continuing operations	$	(0.18	)	$	0.5		$	0.45		$	(0.86	)
	Discontinued operations		—			—			0.01			0.01
	Net income (loss)	$	(0.18	)	$	0.5		$	0.46		$	(0.85	)

Supplemental_Information_on_Oi

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	'
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	'
	(18) Supplemental Information on Oil and Gas Producing Activities (Unaudited)
	The following is supplemental information regarding our consolidated oil and gas producing activities. The amounts shown include our net working interests in all of our oil and gas properties.
	(a)   Capitalized Costs Relating to Oil and Gas Producing Activities
		Year ended December 31
		2012			2013
		(In thousands)
	Proved properties	$	1,682,297		$	3,621,672
	Unproved properties		1,243,237			1,513,136
			2,925,534			5,134,808
	Accumulated depreciation and depletion		(158,210	)		(383,921	)
	Net capitalized costs	$	2,767,324		$	4,750,887
	(b)   Costs Incurred in Certain Oil and Gas Activities
		Year ended December 31
		2011			2012			2013
	Acquisition costs:
	Proved property	$	105,405		$	10,254		$	15,300
	Unproved property		195,131			687,403			440,825
	Development costs		432,147			678,276			780,583
	Exploration costs		95,563			158,074			835,382
	Total costs incurred	$	828,246		$	1,534,007		$	2,072,090
	(c)   Results of Operations (Including Discontinued Operations) for Oil and Gas Producing Activities
		Year ended December 31
		2011			2012			2013
	Revenues	$	391,994		$	390,378		$	821,445
	Operating expenses:
	Production expenses		136,635			185,505			278,348
	Exploration expenses		9,876			15,339			22,272
	Depreciation and depletion		164,011			181,664			219,830
	Impairment of unproved properties		11,051			13,032			10,928
	Results of operations before income tax expense (benefit)		70,421			(5,162	)		290,067
	Income tax (expense) benefit		(26,056	)		2,008			(110,805	)
	Results of operations	$	44,365		$	(3,154	)	$	179,262
	(d)   Oil and Gas Reserves
	The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the oil and gas segment's royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the year ended December 31, 2011, 2012, and 2013 were prepared by the Company's reserve engineers and audited by DeGolyer and MacNaughton (D&M) or Ryder Scott utilizing data compiled by us. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States.
	Proved reserves are the estimated quantities of crude oil, condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months.
	Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company's development plans. The Company's development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital; future oil and gas prices; and cash flows from operations, future drilling costs, demand for natural gas, and other economic factors.
		Natural			NGLS			Oil and			Equivalents
		gas			(MMBbl)			condensate			(Bcfe)
		(Bcf)						(MMBbl)
	Proved reserves:
	December 31, 2010		2,543			104			10			3,231
	Revisions		(223	)		2			7			(172	)
	Extensions, discoveries and other additions		1,644			57			—	(a)		1,982
	Production		(84	)		(1	)		—	(a)		(89	)
	Purchase of reserves		52			2						66
	Sales of reserves in place		(1	)		—			—			(1	)
	December 31, 2011		3,931			164			17			5,017
	Revisions		198			4			—	(a)		222
	Extensions, discoveries and other additions		1,242			115			3			1,951
	Production		(87	)		—	(a)		—	(a)		(87	)
	Sale of reserves in place		(1,590	)		(80	)		(17	)		(2,174	)
	December 31, 2012		3,694			203			3			4,929
	Revisions		152			(140	)		—	(a)		(788	)
	Extensions, discoveries and other additions		3,084			76			7			3,682
	Production		(177	)		(2	)		—	(a)		(191	)
	December 31, 2013		6,753			137			10			7,632
	(a)
	Less than 1.0.
		Natural			NGLS			Oil and			Equivalents
		gas			(MMBbl)			condensate			(Bcfe)
		(Bcf)						(MMBbl)
	Proved developed reserves:
	December 31, 2011		718			19			2			844
December 31, 2012		828			36			1			1,047
December 31, 2013		1,818			33			2			2,022
Proved undeveloped reserves:
December 31, 2011		3,213			145			15			4,173
December 31, 2012		2,866			167			2			3,882
December 31, 2013		4,936			105			8			5,610
Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2010, 2011, and 2012 in the above table include the following:
•
2011—Of the 1,982 Bcfe of extensions and discoveries in 2011, 93 Bcfe related to the Arkoma Basin in Oklahoma, 61 Bcfe related to the Piceance Basin in Colorado, 1,816 Bcfe related to the Appalachian Basin in Pennsylvania and West Virginia, and 12 Bcfe related to other areas. Revisions include negative revisions of 6 Bcfe due to price, negative revisions of 346 Bcfe due to performance, and positive revisions of 180 Bcfe due to the execution of gas processing agreements in the Appalachian Basin. Extensions and discoveries are primarily the result of increased development activity in the Appalachian Basin.
•
2012—Extensions, discoveries, and other additions during 2012 of 1,951 Bcfe were added through the drilling in the Marcellus and Utica Shales, including the addition of 709 Bcfe attributable to NGLs and oil. Downward price revisions resulted in a reduction of proved reserves of 102 Bcfe. Performance revisions increased proved reserves by 324 Bcfe. Sales of proved reserves of 2,174 Bcfe are the result of the sale of our Arkoma and Piceance Basin properties.
•
2013—Extensions, discoveries, and other additions during 2013 of 3,682 Bcfe were added through exploratory and developmental drilling in the Marcellus and Utica Shales. Downward revisions of 788 Bcfe resulted from changing the underlying production assumption used to estimate reserves to ethane rejection at December 31, 2013 from ethane recovery at December 31, 2012 as well as the reclassification of certain wells to the probable reserves category in 2013 because they are no longer expected to be drilled within five years of initial booking.
The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows were computed by applying historical 12-month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.
Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards, and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.
	Year ended December 31
	2011			2012			2013
Future cash inflows	$	20,046		$	12,151		$	30,113
Future production costs		(3,491	)		(1,660	)		(5,967	)
Future development costs		(5,085	)		(3,270	)		(5,349	)
Future net cash flows before income tax		11,470			7,221			18,797
Future income tax expense		(3,287	)		(1,603	)		(5,308	)
Future net cash flows		8,183			5,618			13,489
10% annual discount for estimated timing of cash flows		(5,713	)		(4,017	)		(8,979	)
Standardized measure of discounted future net cash flows	$	2,470		$	1,601		$	4,510
The 12-month weighted average prices used to estimate the Company's total equivalent reserves were as follows:
	Arkoma			Piceance			Appalachia
	(Per Mcfe)
December 31, 2011	$	3.9		$	3.84		$	4.16
December 31, 2012		NA			NA			2.78
December 31, 2013		NA			NA			3.95
(f)    Changes in Standardized Measure of Discounted Future Net Cash Flow
	Year ended December 31
	2011			2012			2013
Sales of oil and gas, net of productions costs	$	(255	)	$	(147	)	$	(761	)
Net changes in prices and production costs		215			(1,631	)		1,061
Development costs incurred during the period		247			296			384
Net changes in future development costs		(106	)		(92	)		(181	)
Extensions, discoveries and other additions		1,684			813			3,441
Acquisitions		51			—			2
Divestitures					(1,277	)		—
Revisions of previous quantity estimates		(182	)		88			(270	)
Accretion of discount		147			322			192
Net change in income taxes		(605	)		653			(1,165	)
Other changes		177			106			206
Net increase (decrease)		1,373			(869	)		2,909
Beginning of year		1,097			2,470			1,601
End of year	$	2,470		$	1,601		$	4,510

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
Basis of Presentation	'
	(a)   Basis of Presentation
	The accompanying consolidated financial statements include the accounts of Antero Resources Corporation and its subsidiary. All significant intercompany accounts and transactions have been eliminated.
	As of the date these financial statements were filed with the Securities and Exchange Commission, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.
Use of Estimates	'
	(b)   Use of Estimates
	The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.
	The Company's consolidated financial statements are based on a number of significant estimates including estimates of gas and oil reserve quantities, which are the basis for the calculation of depreciation, depletion, amortization, present value of cash flows from reserves, and impairment of oil and gas properties. Reserve estimates by their nature are inherently imprecise.
Risks and Uncertainties	'
	(c)   Risks and Uncertainties
	Historically, the market for natural gas, NGLs, and oil has experienced significant price fluctuations. Prices for natural gas have been particularly volatile in recent years. The price fluctuations can result from variations in weather, levels of production in the region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in prices received could have a significant impact on the Company's future results of operations.
Cash and Cash Equivalents	'
	(d)   Cash and Cash Equivalents
	The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Oil and Gas Properties	'
	(e)   Oil and Gas Properties
	The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, costs of productive wells, development dry holes, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The Company reviews exploration costs related to wells-in-progress at the end of each quarter and makes a determination based on known results of drilling at that time whether the costs should continue to be capitalized pending further well testing and results or charged to expense. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
	Unproved properties with significant acquisition costs are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Other unproved properties are assessed for impairment on an aggregate basis. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognizing any gain or loss until the cost has been recovered. Impairment of unproved properties for leases which have expired or are expected to expire was $11.1 million, $13.0 million, and $10.9 million for the years ended December 31, 2011, 2012, and 2013, respectively.
	The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that the carrying value of the properties may not be recoverable. When determining whether impairment has occurred, the Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company reduces the carrying amount of the properties to their estimated fair value. The factors used to determine fair value include estimates of proved reserves, future commodity prices, cash flow from commodity hedges, future production estimates, anticipated capital expenditures, and a commensurate discount rate. There were no impairments of proved natural gas properties during the years ended December 31, 2011, 2012, and 2013.
	At December 31, 2013, the Company did not have significant capitalized costs related to exploratory wells-in-progress which were pending determination of proved reserves. The Company had no significant costs which have been deferred for longer than one year pending proved reserves at December 31, 2013.
	The provision for depreciation, depletion, and amortization of oil and gas properties is calculated on a geological reservoir basis using the units-of-production method. Depreciation, depletion, and amortization expense for oil and gas properties was $164.0 million, $181.7 million, and $219.8 million for the years ended December 31, 2011, 2012, and 2013, respectively.
Gathering Pipelines, Compressor Stations, and Fresh Water Distribution Systems	'
	(f)    Gathering Pipelines, Compressor Stations, and Fresh Water Distribution Systems
	Gathering pipelines and compressor stations are depreciated using the straight-line method over their estimated useful life of 20 years. Fresh water distribution systems are depreciated over useful lives of from 5 to 20 years. Expenditures for installation, major additions, and improvements are capitalized, and minor replacements, maintenance, and repairs are charged to expenses as incurred. For the years ended December 31, 2011, 2012, and 2013, depreciation expense for gathering pipelines, compressor stations, and fresh water distribution systems was $5.5 million, $7.4 million, and $11.9 million, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.
Impairment of Long Lived Assets Other than Oil and Gas Properties	'
	(g)   Impairment of Long-Lived Assets Other than Oil and Gas Properties
	The Company evaluates its long-lived assets other than natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amount of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the unit being assessed. If the carrying value amounts of the assets are deemed to be not recoverable, the carrying amount is reduced to the estimated fair value, which is based on discounted future cash flows or other techniques, as appropriate. No impairments for such assets have been recorded through December 31, 2013.
Other Property and Equipment	'
	(h)   Other Property and Equipment
	Other property and equipment is depreciated using the straight-line method over estimated useful lives ranging from three to five years. For the years ended December 31, 2011, 2012, and 2013, depreciation expense for other property and equipment was $1.0 million, $1.7 million, and $2.2 million, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.
Deferred Financing Costs	'
	(i)    Deferred Financing Costs
	Deferred financing costs represent loan origination fees, initial purchasers' discounts, and other borrowing costs and are included in noncurrent other assets on the consolidated balance sheets. These costs are being amortized over the term of the related debt using the effective interest method. The Company charges interest expense for deferred financing costs remaining for debt facilities that have been retired prior to their maturity date. At December 31, 2013, the Company had $28 million of unamortized deferred financing costs included in other long-term assets. The amounts amortized and the write-off of previously deferred debt issuance costs were $3.8 million, $5.2 million, and $15.8 million for the years ended December 31, 2011, 2012, and 2013, respectively.
Derivative Financial Instruments	'
	(j)    Derivative Financial Instruments
	In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position.
	The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues, and changes in the fair value of interest rate derivatives are classified as other income (expense).
Asset Retirement Obligations	'
	(k)   Asset Retirement Obligations
	The Company is obligated to dispose of certain long-lived assets upon their abandonment. The Company's asset retirement obligations (ARO) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their life. The ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company's credit-adjusted, risk-free interest rate. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation and interest rates, and changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement.
	The Company delivers natural gas through its gathering assets and delivers water through its water distribution assets and may become obligated by regulatory or other requirements to remove certain facilities or perform other remediation upon retirement of gathering pipelines and compressor stations. However, the Company cannot reasonably predict when production from existing reserves of the fields in which we operate will cease. In the absence of such information, we are not able to make a reasonable estimate of when future dismantlement and removal dates will occur and therefore have not recorded asset retirement obligations related to gathering assets.
Environmental Liabilities	'
	(l)    Environmental Liabilities
	Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable, and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2012 and 2013, the Company has not accrued a material amount for any environmental liabilities nor has it been fined or cited for any environmental violations that could have a material adverse effect on future capital expenditures or operating results of the Company.
Natural Gas, NGL and Oil Revenues	'
	(m)  Natural Gas, NGL and Oil Revenues
	Sales of natural gas, NGLs, and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one month after the sale has occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a revenue distribution payable to the extent it receives more than its proportionate share natural gas revenues. At December 31, 2012 and 2013, the Company had no significant imbalance positions.
Concentrations of Credit Risk	'
	(n)   Concentrations of Credit Risk
	The Company's revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry. The concentration of credit risk in a single industry affects the Company's overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables.
	The Company's sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2011, 2012, and 2013 are as follows (including sales in discontinued operations):
		2011			2012			2013
	Company A		28	%		23	%		30	%
	Company B		17			13			14
	Company C		12			10			8
	All others		43			54			48
			100	%		100	%		100	%
	Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.
	The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations. The fair value of our commodity derivative contracts of approximately $860 million at December 31, 2013 includes the following values by bank counterparty: BNP Paribas—$197 million; Credit Suisse—$190 million; Barclays—$147 million; Wells Fargo—$140 million; JP Morgan—$134 million; Citigroup—$34 million; Deutsche Bank—$15 million; and Toronto Dominion Bank—$3 million. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates at December 31, 2013 for each of the European and American banks. We believe that all of these institutions currently are acceptable credit risks.
	The Company, at times, may have cash in banks in excess of federally insured amounts.
Income Taxes	'
	o)   Income Taxes
	The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance, when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
	Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties as income tax expense.
Fair Value Measures	'
	(p)   Fair Value Measures
	FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties, and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include nonexchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, and interest rate swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.
Industry Segment and Geographic Information	'
	(q)   Industry Segment and Geographic Information
	We have evaluated how the Company is organized and managed and have identified the following operating segments: (1) the exploration and production of oil, natural gas, and natural gas liquids, and (2) midstream operations consisting of natural gas gathering, compression, and fresh water distribution operations for the distribution of fresh water used in well completions. Prior to 2013, the Company did not have any reportable segments and considered its gathering, compression, and fresh water distribution operations to be ancillary to its exploration and production activities. In connection with the proposed initial public offering of Antero Midstream, the Company intends to contribute its midstream assets to Antero Midstream. Antero Midstream is expected to enter into agreements with the Company for the dedication of substantially all of the Company's current and future acreage for natural gas gathering and compression services and for fresh water sourcing and delivery related to all of the Company's current and future drilling. The Company intends to convert Antero Midstream into a limited partnership in connection with a public offering of Antero Midstream as a master limited partnership. As a result of these transactions, management has begun to evaluate these gathering and compression and fresh water distribution services separately from exploration and production activities and these operations therefore became reportable segments as of December 31, 2013. Prior to 2013 and the planned master limited partnership, gathering and compression and fresh water distribution services were not material.
	All of our assets are located in the United States and all of our revenues are attributable to customers located in the United States.
Reclassifications	'
	(r)   Reclassifications
	Certain reclassifications have been made to prior periods' financial information related to water distribution assets to conform to the 2013 presentation.
Earnings (loss) per share	'
	(s)   Earnings (loss) per share.
	Earnings (loss) per common share and earnings (loss) per common share—assuming dilution for each of the three years ended December 31, 2013 was calculated as if the shares issued in the Corporate Reorganization and IPO described in Note 1 were outstanding for the entire period. The effect of dilutive options and restricted stock awards in 2013 is less than $0.01 per share.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Significant Accounting Policies	'
Schedule of the Company's sales to major customers including sales in discontinued operations (purchases in excess of 10% of total sales)	'
	The Company's sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2011, 2012, and 2013 are as follows (including sales in discontinued operations):
		2011			2012			2013
	Company A		28	%		23	%		30	%
	Company B		17			13			14
	Company C		12			10			8
	All others		43			54			48
			100	%		100	%		100	%

Sale_of_Piceance_and_Arkoma_Pr1

Sale of Piceance and Arkoma Properties - Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
Sale of Piceance and Arkoma Properties - Discontinued Operations	'
Schedule of results of operations and the loss on the sale of the Piceance Basin and Arkoma Basin assets shown as discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss)	'
	Results of operations and the loss on the sale of the Piceance Basin and Arkoma Basin assets are shown as discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss) and are comprised of the following (in thousands):
		Year ended December 31
		2011			2012			2013
	Sales of oil, natural gas, and natural gas liquids	$	196,705		$	125,396		$	—
	Commodity derivative fair value gains		180,130			46,358			—
	Total revenues		376,835			171,754			—
	Lease operating		26,037			19,901			—
	Gathering, compression, and transportation		50,453			45,089			—
	Production taxes		6,307			2,967			—
	Exploration		5,842			664			—
	Impairment of unproved properties		6,387			962			—
	Depletion, depreciation, and amortization		114,805			88,720			—
	Accretion of asset retirement obligations		359			404			—
	Loss on sale of assets		—			795,945			(8,506	)
	Total expenses		210,190			954,652			(8,506	)
	Income (loss) from discontinued operations before income taxes		166,645			(782,898	)		8,506
	Income tax (expense) benefit		(45,155	)		272,553			(3,249	)
	Net income (loss) from discontinued operations	$	121,490		$	(510,345	)	$	5,257

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Long-Term Debt	'
Schedule of long-term debt	'
	The Company's had long-term debt as follows at December 31, 2012 and 2013 (in thousands):
		2012		2013
	Bank credit facility(a)	$	217,000	$	288,000
	9.375% senior notes due 2017(b)		525,000		—
	7.25% senior notes due 2019(c)		400,000		260,000
	6.00% senior notes due 2020(d)		300,000		525,000
	5.375% senior notes due 2021(e)		—		1,000,000
	9.00% senior note due 2013(f)		25,000		—
	Net unamortized premium		2,058		5,999
			1,469,058		2,078,999
	Less amounts due within one year		25,000		—
		$	1,444,058	$	2,078,999

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations	'
Schedule of reconciliation of asset retirement obligations	'
	The following is a reconciliation of the Company's asset retirement obligations for the years ended December 31, 2012 and 2013 (in thousands).
		2012			2013
	Asset retirement obligations—beginning of year	$	6,715		$	10,552
	Obligations incurred for wells drilled or on properties acquired		9,440			242
	Obligations related to assets sold		(6,107	)		—
	Accretion expense		504			1,065
	Asset retirement obligations—end of year	$	10,552		$	11,859

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Stock-Based Compensation	'
Schedule of stock-based compensation expense	'
	Our stock-based compensation expense is as follows for the year ended December 31, 2013 (in thousands):
	Profits interests awards (see note 8)	$	364,957
	Restricted stock		219
	Stock options		104
	Total expense	$	365,280
Summary of restricted stock awards activity	'
		Number of		Weighted		Aggregate
		shares		average		intrinsic value
				grant date		(in thousands)
				fair value
	Total granted and unvested, January 1, 2013		—		—		—
	Granted		45,093	$	54.27
	Vested		—
	Forfeited		—
	Total awarded and unvested—December 31, 2013		45,093	$	54.27	$	2,861
Schedule of outstanding unvested restricted stock awards vesting schedule	'
	Vesting date	Number of
		awards
	2014		20,818
	2015		8,092
	2016		8,092
	2017		8,091
Summary of stock option activity	'
		Stock options		Weighted		Weighted		Intrinsic
				average		average		value
				exercise		remaining		(in thousands)
				price		contractual
						life
	Outstanding at January 1, 2013		—		—		—		—
	Options granted		70,339	$	54.15
	Options exercised		—		—
	Options cancelled		—		—
	Options expired		—		—
	Outstanding at December 31, 2013		70,339	$	54.15
	Vested or expected to vest as of December 31, 2013		70,339	$	54.15		9.79	$	653
	Exercisable at December 31, 2013		—				9.79	$	653
Schedule of information regarding weighted average fair value of options granted and the assumptions used to determine fair value	'
	The outstanding unvested restricted stock awards at December 31, 2013 are scheduled to vest as follows:
	Vesting date	Number of
		awards
	2014		20,818
	2015		8,092
	2016		8,092
	2017		8,091

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments	'
Schedule of outstanding commodity derivatives	'
	As of December 31, 2013, the Company has entered into fixed price natural gas and oil swaps in order to hedge a portion of its natural gas and oil production from January 1, 2014 through December 31, 2019 as summarized in the following table.
		Natural gas			Oil			Weighted
		MMbtu/day			Bbls/day			average index
								price
	Year ending December 31, 2014:
	CGTAP-TCO		210,000			—		$	5.11
	Dominion South		160,000			—			5.15
	NYMEX		230,000			—			3.99
	CGLA		10,000			—			3.87
	NYMEX-WTI		—			3,000			96.53
	2014 Total		610,000			3,000
	Year ending December 31, 2015:
	CGTAP-TCO		130,000					$	4.93
	Dominion South		230,000						5.6
	NYMEX		140,000						4.08
	CGLA		40,000						4
	2015 Total		540,000
	Year ending December 31, 2016:
	CGTAP-TCO		80,000					$	4.67
	Dominion South		272,500						5.35
	NYMEX		110,000						4.18
	CGLA		170,000						4.09
	2016 Total		632,500
	Year ending December 31, 2017:
	CGTAP-TCO		20,000					$	4.02
	NYMEX		230,000						4.43
	CGLA		420,000						4.27
	CCG		70,000						4.57
	2017 Total		740,000
	Year ending December 31, 2018:
	NYMEX		620,000					$	4.66
	Year ending December 31, 2019:
	CGLA		277,500					$	4.51
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	'
		2012					2013
		Balance sheet		Fair value			Balance sheet		Fair value
		location					location
				(In thousands)					(In thousands)
	Asset derivatives not designated as hedges for accounting purposes:
	Commodity contracts	Current assets		$	160,579		Current assets		$	183,000
	Commodity contracts	Long-term assets			371,436		Long-term assets			677,780
	Total asset derivatives			$	532,015				$	860,780
	Liability derivatives not designated as hedges for accounting purposes:
	Commodity contracts	Current liabilities			—					646
	Net derivatives			$	532,015				$	860,134
Schedule of gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts	'
	The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value (in thousands):
											December 31, 2013
		December 31, 2012
																Net amounts
																of assets
																(liabilities)
																on balance
		Gross amounts			Gross amounts			Net amounts			Gross amounts		Gross amounts			sheet
		of recognized			offset on			of assets			of recognized		offset on
		assets			balance sheet			on balance			assets		balance sheet
								sheet
	Commodity derivative assets	$	597,359		$	(65,344	)	$	532,015		$	887,034	$	(26,254	)	$	860,780
	Commodity derivative liabilities		—			—			—			—		(646	)		(646	)
Summary of derivative fair value gains (losses)	'
	The following is a summary of derivative fair value gains (losses) and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2011, 2012, and 2013 (in thousands):
		Statement of operations		2011			2012			2013
		location
	Commodity derivative fair value gains	Revenue		$	496,064		$	179,546		$	491,689
	Commodity derivative fair value gains	Discontinued operations			180,130			46,358			—
	Total commodity derivative fair value gains				676,194			225,904			491,689
	Interest rate derivative fair value losses	Other expenses			(94	)		—			—
	Net derivative fair value gains			$	676,100		$	225,904		$	491,689

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
Schedule of income tax expense from continuing operations	'
	For the years ended December 31, 2011, 2012, and 2013 income tax expense from continuing operations consisted of the following (in thousands):
		2011			2012			2013
	Current income tax expense (benefit)	$	—		$	15,000		$	(4,000	)
	Deferred income tax expense		185,297			106,229			190,210
	Total income tax expense from continuing operations	$	185,297		$	121,229		$	186,210
Schedule of reconciliation of income tax expense from continuing operations	'
	The income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to consolidated income for the years ended December 31, 2011, 2012, and 2013, as a result of the following (in thousands):
		2011			2012			2013
	Federal income tax expense	$	159,770		$	121,276		$	56,708
	State income tax expense, net of federal benefit		23,593			4,761			21,429
	Nondeductible stock compensation		—			—			127,736
	Change in valuation allowance		(934	)		(4,872	)		(20,919	)
	Other		2,868			64			1,256
	Total income tax expense from continuing operations	$	185,297			121,229			186,210
Schedule of income tax expense (benefit) allocated to continuing and discontinued operations	'
	For the years ended December 31, 2011, 2012, and 2013 income tax expense (benefit) was allocated to continuing and discontinued operations as follows (in thousands):
		2011			2012			2013
	Continuing operations	$	185,297		$	121,229		$	186,210
	Discontinued operations and sale of discontinued operations		45,155			(272,553	)		3,249
	Total income tax expense (benefit)	$	230,452		$	(151,324	)	$	189,459
Schedule of net deferred tax assets and liabilities	'
	The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities at December 31, 2012 and 2013 is as follows (in thousands):
		2012			2013
	Deferred tax assets:
	Net operating loss carryforwards	$	417,385		$	449,961
	Capital loss carryforwards		5,367			—
	Minimum tax credit carryforward		15,000			11,000
	Other		5,006			5,373
	Total deferred tax assets		442,758			466,334
	Valuation allowance		(47,678	)		(26,759	)
	Net deferred tax assets		395,080			439,575
	Deferred tax liabilities:
	Unrealized gains on derivative instruments		206,937			328,534
	Oil and gas properties		342,455			458,812
	Total deferred tax liabilities		549,392			787,346
	Net deferred tax liabilities	$	(154,312	)	$	(347,771	)
Schedule of reconciliation of beginning and ending amount of unrecognized tax benefits	'
		2013
	Balance at beginning of year	$	15,000
	Revised estimate of unrecognized tax position		(4,000	)
	Balance at end of year	$	11,000

Commitments_Tables

Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments	'
Schedule of future minimum payments for firm transportation agreements, drilling and compression facility obligations, and leases	'
	The following is a schedule of future minimum payments for firm transportation agreements, drilling and compression facility obligations, and leases that have remaining lease terms in excess of one year as of December 31, 2013 (in millions).
		Firm		Gas processing,		Drilling rigs		Office and		Total
		transportation		gathering and		and frac		equipment
		(a)		compression		Services		(d)
				(b)		(c)
	Year ending December 31:
	2014	$	120.5	$	182.8	$	150.9	$	3.9	$	458.1
	2015		159.5		184.7		68.3		4.1		416.6
	2016		160.9		196.1		13.7		3.8		374.5
	2017		158.4		192.5		—		3.2		354.1
	2018		159		189.1		—		1.5		349.6
	Thereafter		1,002.90		836.1		—		14.1		1,853.10
	Total	$	1,761.20	$	1,781.30	$	232.9	$	30.6	$	3,806.00

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Information	'
Schedule of operating results and assets of reportable segments	'
	The operating results and assets of the Company's reportable segments were as follows for 2013 (in thousands):
		Exploration and		Gathering and		Fresh water		Elimination of			Consolidated
		production		compression		distribution		intersegment			total
								transactions
	2013:00:00
	Sales and revenues:
	Third-party	$	1,313,134		—		—		—			1,313,134
	Intersegment		—		22,363		35,871		(58,234	)		—
		$	1,313,134		22,363		35,871		(58,234	)		1,313,134
	Depiction, depreciation, and amortization	$	220,857		11,346		2,773		(1,100	)		233,876
	Interest expense	$	136,453		155		9		—			136,617
	Income tax expense	$	186,210		—		—		—			186,210
	Operating income(1)	$	335,901		8,938		27,296		(30,928	)		341,207
	Segment assets	$	6,580,282		561,855		230,247		(758,803	)		6,613,581
	Capital expenditures for	$	2,110,358		389,453		203,790		(32,028	)		2,671,573
	segment assets
	-1
	All general and administrative expenses are included in the exploration and production segment.

Subsidiary_Guarantor_Tables

Subsidiary Guarantor (Tables)	12 Months Ended
	Dec. 31, 2013
Subsidiary Guarantor	'
Schedule of condensed consolidated balance sheets	'
	Condensed Consolidating Balance Sheets
	December 31, 2013
	(In thousands)
		Parent		Guarantor		Eliminations			Consolidated
				Subsidiary
	Assets
	Current assets:
	Cash and cash equivalents	$	17,487	$	—	$	—		$	17,487
	Other		316,077		1		(1	)		316,077
	Total current assets		333,564		1		(1	)		333,564
	Property and equipment, net		5,559,656		—		—			5,559,656
	Other long-term assets		720,361		—		—			720,361
	Investment in subsidiary		1		—		(1	)		—
		$	6,613,582	$	1	$	(2	)	$	6,613,581
	Liabilities and Stockholders' Equity
	Current liabilities	$	622,229	$	—	$			$	622,229
	Long-term debt		2,078,999		—		—			2,078,999
	Other long-term liabilities		313,693		—		—			313,693
	Due to subsidiary		1		—		(1	)		—
	Total liabilities		3,014,922		—		(1	)		3,014,921
	Stockholders' or member's equity		3,598,660		1		(1	)		3,598,660
	Total liabilities and equity	$	6,613,582	$	1	$	(2	)	$	6,613,581

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information (Unaudited)	'
Schedule of quarterly financial information	'
	The Company's quarterly financial information for the years ended December 31, 2012 and 2013 is as follows (in thousands, except per share amounts):
		First			Second			Third			Fourth
		quarter			quarter			quarter			quarter
	Year ended December 31, 2012:
	Total operating revenues	$	553,741		$	38,925		$	(92,038	)	$	235,090
	Total operating expenses		43,405			62,381			74,840			111,077
	Operating income (loss)		510,336			(23,456	)		(166,878	)		124,013
	Income (loss) from continuing operations		287,555			(33,237	)		(113,887	)		84,845
	Income (loss) from discontinued operations		40,176			(444,850	)		(13,791	)		(91,880	)
	Net income (loss)		327,731			(478,087	)		(127,678	)		(7,035	)
	Earnings (loss) per common share—basic:
	Continuing operations	$	1.1		$	(0.12	)	$	(0.44	)	$	0.32
	Discontinued operations		0.15			(1.70	)		(0.05	)		(0.35	)
	Net income (loss)	$	1.25		$	(1.82	)	$	(0.49	)	$	(0.03	)
	Earnings (loss) per common share—diluted:
	Continuing operations	$	1.1		$	(0.12	)	$	(0.44	)	$	0.32
	Discontinued operations		0.15			(1.70	)		(0.05	)		(0.35	)
	Net income (loss)	$	1.25		$	(1.82	)	$	(0.49	)	$	(0.03	)
		First			Second			Third			Fourth
		quarter			quarter			quarter			quarter
	Year Ended December 31, 2013:
	Total operating revenues	$	61,454		$	387,144		$	384,522		$	480,014
	Total operating expenses		109,923			138,758			161,914			561,332
	Operating income (loss)		(48,469	)		248,386			222,608			(81,318	)
	Income (loss) from continuing operations		(47,997	)		131,193			117,794			(225,177	)
	Income (loss) from discontinued operations		—			—			3,100			2,157
	Net income (loss)		(47,997	)		131,193			120,894			(223,020	)
	Earnings (loss) per common share—basic:
	Continuing operations	$	(0.18	)	$	0.5		$	0.45		$	(0.86	)
	Discontinued operations		—			—			0.01			0.01
	Net income (loss)	$	(0.18	)	$	0.5		$	0.46		$	(0.85	)
	Earnings (loss) per common share—diluted:
	Continuing operations	$	(0.18	)	$	0.5		$	0.45		$	(0.86	)
	Discontinued operations		—			—			0.01			0.01
	Net income (loss)	$	(0.18	)	$	0.5		$	0.46		$	(0.85	)

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	'
Schedule of capitalized costs relating to oil and gas producing activities	'
		Year ended December 31
		2012			2013
		(In thousands)
	Proved properties	$	1,682,297		$	3,621,672
	Unproved properties		1,243,237			1,513,136
			2,925,534			5,134,808
	Accumulated depreciation and depletion		(158,210	)		(383,921	)
	Net capitalized costs	$	2,767,324		$	4,750,887
Schedule of costs incurred in certain oil and gas activities	'
		Year ended December 31
		2011			2012			2013
	Acquisition costs:
	Proved property	$	105,405		$	10,254		$	15,300
	Unproved property		195,131			687,403			440,825
	Development costs		432,147			678,276			780,583
	Exploration costs		95,563			158,074			835,382
	Total costs incurred	$	828,246		$	1,534,007		$	2,072,090
Schedule of results of operations (including discontinued operations) for oil and gas producing activities	'
		Year ended December 31
		2011			2012			2013
	Revenues	$	391,994		$	390,378		$	821,445
	Operating expenses:
	Production expenses		136,635			185,505			278,348
	Exploration expenses		9,876			15,339			22,272
	Depreciation and depletion		164,011			181,664			219,830
	Impairment of unproved properties		11,051			13,032			10,928
	Results of operations before income tax expense (benefit)		70,421			(5,162	)		290,067
	Income tax (expense) benefit		(26,056	)		2,008			(110,805	)
	Results of operations	$	44,365		$	(3,154	)	$	179,262
Schedule of proved developed and undeveloped reserves	'
		Natural			NGLS			Oil and			Equivalents
		gas			(MMBbl)			condensate			(Bcfe)
		(Bcf)						(MMBbl)
	Proved reserves:
	December 31, 2010		2,543			104			10			3,231
	Revisions		(223	)		2			7			(172	)
	Extensions, discoveries and other additions		1,644			57			—	(a)		1,982
	Production		(84	)		(1	)		—	(a)		(89	)
	Purchase of reserves		52			2						66
	Sales of reserves in place		(1	)		—			—			(1	)
	December 31, 2011		3,931			164			17			5,017
	Revisions		198			4			—	(a)		222
	Extensions, discoveries and other additions		1,242			115			3			1,951
	Production		(87	)		—	(a)		—	(a)		(87	)
	Sale of reserves in place		(1,590	)		(80	)		(17	)		(2,174	)
	December 31, 2012		3,694			203			3			4,929
	Revisions		152			(140	)		—	(a)		(788	)
	Extensions, discoveries and other additions		3,084			76			7			3,682
	Production		(177	)		(2	)		—	(a)		(191	)
	December 31, 2013		6,753			137			10			7,632
	(a)
	Less than 1.0.
Schedule of proved developed and undeveloped reserves by fiscal year maturity	'
		Natural			NGLS			Oil and			Equivalents
		gas			(MMBbl)			condensate			(Bcfe)
		(Bcf)						(MMBbl)
	Proved developed reserves:
	December 31, 2011		718			19			2			844
	December 31, 2012		828			36			1			1,047
	December 31, 2013		1,818			33			2			2,022
	Proved undeveloped reserves:
	December 31, 2011		3,213			145			15			4,173
	December 31, 2012		2,866			167			2			3,882
	December 31, 2013		4,936			105			8			5,610
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	'
		Year ended December 31
		2011			2012			2013
	Future cash inflows	$	20,046		$	12,151		$	30,113
	Future production costs		(3,491	)		(1,660	)		(5,967	)
	Future development costs		(5,085	)		(3,270	)		(5,349	)
	Future net cash flows before income tax		11,470			7,221			18,797
	Future income tax expense		(3,287	)		(1,603	)		(5,308	)
	Future net cash flows		8,183			5,618			13,489
	10% annual discount for estimated timing of cash flows		(5,713	)		(4,017	)		(8,979	)
	Standardized measure of discounted future net cash flows	$	2,470		$	1,601		$	4,510
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	'
		Arkoma			Piceance			Appalachia
		(Per Mcfe)
	December 31, 2011	$	3.9		$	3.84		$	4.16
	December 31, 2012		NA			NA			2.78
	December 31, 2013		NA			NA			3.95
Schedule of changes in standardized measure of discounted future net cash flow	'
		Year ended December 31
		2011			2012			2013
	Sales of oil and gas, net of productions costs	$	(255	)	$	(147	)	$	(761	)
	Net changes in prices and production costs		215			(1,631	)		1,061
	Development costs incurred during the period		247			296			384
	Net changes in future development costs		(106	)		(92	)		(181	)
	Extensions, discoveries and other additions		1,684			813			3,441
	Acquisitions		51			—			2
	Divestitures					(1,277	)		—
	Revisions of previous quantity estimates		(182	)		88			(270	)
	Accretion of discount		147			322			192
	Net change in income taxes		(605	)		653			(1,165	)
	Other changes		177			106			206
	Net increase (decrease)		1,373			(869	)		2,909
	Beginning of year		1,097			2,470			1,601
	End of year	$	2,470		$	1,601		$	4,510

Organization_Details

Organization (Details) (USD $)	12 Months Ended			0 Months Ended			0 Months Ended
	Dec. 31, 2013	Oct. 15, 2013	Dec. 31, 2012	Oct. 16, 2013	Jun. 30, 2013	Oct. 15, 2013	Oct. 16, 2013
				IPO	Antero Resources LLC	Antero Investment	Antero Investment
							IPO
Corporate Reorganization and Initial Public Offering (IPO)	'	'	'	'	'	'	'
Ownership percentage	'	'	'	'	100.00%	100.00%	'
Common stock, shares issued	262,049,659	224,375,000	262,049,659	'	'	'	'
Common stock, shares outstanding	262,049,659	224,375,000	262,049,659	'	'	'	'
Number of additional shares of common stock issued	37,674,659	'	'	37,674,659	'	'	'
Common stock price (in dollars per share)	'	'	'	$44	'	'	'
Net proceeds from issuance of additional shares of common stock	'	'	'	$1,600,000,000	'	'	'
Number of shares of common stock sold	'	'	'	'	'	'	3,409,091
Stock Compensation Charge in Connection with the Reorganization	'	'	'	'	'	'	'
Stock compensation expense recognized	365,280,000	'	'	'	'	'	'
Additional stock compensation to be recognized over the remaining service period	$121,000,000	'	'	'	'	'	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Properties	'	'	'
Impairment of unproved properties for leases expired or expected to expire	$11,000,000	$13,000,000	$11,100,000
Impairment of proved properties	0	0	0
Period of deferment of significant costs, pending proved reserves	'1 year	'	'
Depreciation, depletion, and amortization expense for oil and gas properties	219,800,000	181,700,000	164,000,000
Impairment of long-lived assets other than oil and gas properties	0	'	'
Other Property and Equipment	'	'	'
Depreciation expense	233,876,000	102,026,000	55,716,000
Deferred Financing Costs	'	'	'
Unamortized deferred financing costs included in other long-term assets	28,000,000	'	'
Amounts amortized and the write-off of previously deferred debt issuance costs	15,800,000	5,200,000	3,800,000
Gathering Systems and Facilities	'	'	'
Other Property and Equipment	'	'	'
Estimated useful life	'P20Y	'	'
Other property and equipment	'	'	'
Other Property and Equipment	'	'	'
Depreciation expense	2,200,000	1,700,000	1,000,000
Other property and equipment | Minimum	'	'	'
Other Property and Equipment	'	'	'
Estimated useful life	'P3Y	'	'
Other property and equipment | Maximum	'	'	'
Other Property and Equipment	'	'	'
Estimated useful life	'P5Y	'	'
Gathering pipelines, compressor stations, and fresh water distribution systems	'	'	'
Other Property and Equipment	'	'	'
Depreciation expense	$11,900,000	$7,400,000	$5,500,000
Fresh water distribution systems | Minimum	'	'	'
Other Property and Equipment	'	'	'
Estimated useful life	'P5Y	'	'
Fresh water distribution systems | Maximum	'	'	'
Other Property and Equipment	'	'	'
Estimated useful life	'P20Y	'	'

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Details 2)	12 Months Ended
	Dec. 31, 2013
Natural Gas, NGL and Oil Revenues	'
Collection period for accounts receivable	'1 month

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Details 3) (Sales, Customer concentration)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Concentrations of Credit Risk	'	'	'
Sales to major customers (as a percent)	100.00%	100.00%	100.00%
Company A	'	'	'
Concentrations of Credit Risk	'	'	'
Sales to major customers (as a percent)	30.00%	23.00%	28.00%
Company B	'	'	'
Concentrations of Credit Risk	'	'	'
Sales to major customers (as a percent)	14.00%	13.00%	17.00%
Company C	'	'	'
Concentrations of Credit Risk	'	'	'
Sales to major customers (as a percent)	8.00%	10.00%	12.00%
All others	'	'	'
Concentrations of Credit Risk	'	'	'
Sales to major customers (as a percent)	48.00%	54.00%	43.00%

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Details 4) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013
	item
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	$860
Industry Segment and Geographic Information	'
Number of operating segments	3
Earnings (loss) per share	'
Effect of dilutive options and restricted stock awards (in dollars per share)	$0.01
BNP Paribas	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	197
Credit Suisse	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	190
Barclays	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	147
Wells Fargo	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	140
JP Morgan	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	134
Citigroup	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	34
Deutsche Bank	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	15
Toronto Dominion Bank	'
Derivative Financial Instruments	'
Fair value of commodity derivative contracts	$3

Sale_of_Piceance_and_Arkoma_Pr2

Sale of Piceance and Arkoma Properties - Discontinued Operations (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

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, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 21, 2012

Jun. 29, 2012

Piceance Basin and Arkoma Basin

Piceance Basin and Arkoma Basin

Piceance Basin and Arkoma Basin

Piceance Basin and Arkoma Basin

Piceance Basin

Arkoma properties

Sale of Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from the sale adjusted for expenses of the sale and estimated income, expenses, and capital costs

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$316,000,000

$427,000,000

Purchase Price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

325,000,000

445,000,000

Proceeds from liquidation of hedge positions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100,000,000

'

Results of operations and the loss on the sale of the assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Sales of oil, natural gas, and natural gas liquids

'

'

'

'

'

'

'

'

'

'

'

'

125,396,000

196,705,000

'

'

'

Commodity derivative fair value gains

'

'

'

'

'

'

'

'

491,689,000

179,546,000

496,064,000

'

46,358,000

180,130,000

'

'

'

Gain on sale of midstream assets

'

'

'

'

'

'

'

'

'

291,190,000

'

'

'

'

148,000,000

'

'

Total revenue

480,014,000

384,522,000

387,144,000

61,454,000

235,090,000

-92,038,000

38,925,000

553,741,000

1,313,134,000

735,718,000

691,353,000

'

171,754,000

376,835,000

'

'

'

Lease operating

'

'

'

'

'

'

'

'

9,439,000

6,243,000

4,608,000

'

19,901,000

26,037,000

'

'

'

Gathering, compression, and transportation

'

'

'

'

'

'

'

'

218,428,000

91,094,000

37,315,000

'

45,089,000

50,453,000

'

'

'

Production taxes

'

'

'

'

'

'

'

'

'

'

'

'

2,967,000

6,307,000

'

'

'

Exploration

'

'

'

'

'

'

'

'

22,272,000

14,675,000

4,034,000

'

664,000

5,842,000

'

'

'

Impairment of unproved properties

'

'

'

'

'

'

'

'

10,928,000

12,070,000

4,664,000

'

962,000

6,387,000

'

'

'

Depletion, depreciation, and amortization

'

'

'

'

'

'

'

'

233,876,000

102,026,000

55,716,000

'

88,720,000

114,805,000

'

'

'

Accretion of asset retirement obligations

'

'

'

'

'

'

'

'

1,065,000

101,000

76,000

'

404,000

359,000

'

'

'

Loss on sale of assets

'

'

'

'

'

'

'

'

'

'

'

-8,506,000

795,945,000

'

'

'

432,000,000

Total operating expenses

561,332,000

161,914,000

138,758,000

109,923,000

111,077,000

74,840,000

62,381,000

43,405,000

971,927,000

291,703,000

160,370,000

-8,506,000

954,652,000

210,190,000

'

'

'

Operating income

-81,318,000

222,608,000

248,386,000

-48,469,000

124,013,000

-166,878,000

-23,456,000

510,336,000

341,207,000

444,015,000

530,983,000

8,506,000

-782,898,000

166,645,000

'

'

'

Income tax (expense) benefit

'

'

'

'

'

'

'

'

-3,249,000

272,553,000

-45,155,000

-3,249,000

272,553,000

-45,155,000

'

'

'

Net income (loss) from discontinued operations

$2,157,000

$3,100,000

'

'

($91,880,000)

($13,791,000)

($444,850,000)

$40,176,000

$5,257,000

($510,345,000)

$121,490,000

$5,257,000

($510,345,000)

$121,490,000

'

'

'

Sale_of_Appalachian_Gathering_1

Sale of Appalachian Gathering Assets (Details) (USD $)	12 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2011	Mar. 31, 2012	Dec. 31, 2013	Mar. 26, 2012	Dec. 31, 2013
		Appalachian Gathering Assets	Appalachian Gathering Assets	Appalachian Gathering Assets	Appalachian Gathering Assets
		acre		acre	Maximum
		mi
Sale of Assets	'	'	'	'	'
Period of exclusive rights to gather the gas within AOD	'	'20 years	'	'	'
Purchase Price	'	$375,000,000	'	'	'
Area of low pressure pipeline systems and gathering rights sold (in miles)	'	25	'	'	'
Area of land held (in acres)	'	'	'	104,000	'
Area of AOD (in acres)	'	250,000	'	'	'
Period for which entity is committed to deliver minimum annual volumes into gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies	'	'	'7 years	'	'
Additional sale proceeds on meeting certain volume threshold	'	'	'	'	40,000,000
Earn out period	'	'	'3 years	'	'
Gain recognized on the sale of assets	($8,700,000)	$291,000,000	'	'	'

Notes_Receivable_Details

Notes Receivable (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Notes Receivable	'	'
Notes receivable from a drilling contractor	$2.70	$7.20

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 02, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Nov. 25, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Aug. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Feb. 04, 2013

Dec. 31, 2013

Nov. 19, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 05, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Bank credit facility

Bank credit facility

Bank credit facility

Bank credit facility

9.375% senior notes due 2017

9.375% senior notes due 2017

9.375% senior notes due 2017

9.375% senior notes due 2017

7.25% senior notes due 2019

7.25% senior notes due 2019

7.25% senior notes due 2019

7.25% senior notes due 2019

7.25% senior notes due 2019

7.25% senior notes due 2019

7.25% senior notes due 2019

7.25% senior notes due 2019

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

6.00% senior notes due 2020

5.375% senior notes due 2021

5.375% senior notes due 2021

5.375% senior notes due 2021

5.375% senior notes due 2021

5.375% senior notes due 2021

5.375% senior notes due 2021

9.00% senior note

9.00% senior note

9.00% senior note

Net unamortized premium

Net unamortized premium

Stand-alone revolving note

Minimum

Maximum

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Antero Finance

Maximum

On or after November 1, 2016

On or after November 1, 2019

Prior to November 1, 2016

On or after August 1, 2014

On or after August 1, 2017

On or before August 1, 2014

On or after December 1, 2015

On or after December 1, 2018

On or before December 1, 2015

Prior to December 1, 2015

Prior to January 1, 2014

Antero Finance

On or before December 1, 2015

Long- term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

$2,078,999,000

$1,469,058,000

$288,000,000

$217,000,000

'

'

'

'

$525,000,000

'

'

$260,000,000

$400,000,000

'

'

'

'

'

$525,000,000

$300,000,000

'

'

'

'

'

'

'

'

'

$1,000,000,000

'

'

'

'

'

'

'

$25,000,000

$5,999,000

$2,058,000

'

Less amounts due within one year

'

25,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

2,078,999,000

1,444,058,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate (as a percent)

'

'

'

'

'

'

'

9.38%

9.38%

9.38%

'

7.25%

7.25%

7.25%

'

'

'

'

6.00%

6.00%

'

6.00%

'

'

'

'

'

'

'

5.38%

5.38%

5.38%

'

'

'

'

9.00%

9.00%

'

'

'

Premium Percentage

'

'

'

'

'

'

'

'

'

'

'

107.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum amount of the Credit Facility

'

'

2,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25,000,000

Current borrowing base

'

'

2,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lender commitments

'

'

1,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding balance

'

'

288,000,000

217,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

Weighted average interest rate (as a percent)

'

'

1.61%

1.91%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding letters of credit

'

'

32,000,000

43,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment fees on the unused portion (as a percent)

'

'

'

'

0.38%

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes issued

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000,000

'

'

'

'

'

225,000,000

'

300,000,000

'

'

'

'

'

'

'

1,000,000,000

'

'

'

'

'

'

'

'

'

'

Issue price as percentage of par value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

103.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price of the debt instrument in the event of change of control (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

105.44%

100.00%

100.00%

'

'

'

'

'

104.50%

100.00%

100.00%

'

110.00%

'

'

'

'

104.03%

100.00%

100.00%

'

'

'

'

'

'

Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of the principal amount of the debt instrument redeemed

'

'

'

'

'

'

104.69%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Loss on Early Extinguishment of Debt

-42,567,000

'

'

'

'

'

24,600,000

'

'

'

10,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred financing costs charged to Loss on Early Extinguishment of Debt

'

'

'

'

'

'

5,900,000

'

'

'

1,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior notes redeemed

'

'

'

'

'

'

'

'

'

'

140,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

106.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of principal amount at which notes may be required to be repurchased in event of change of control

'

'

'

'

'

'

'

'

'

'

'

'

'

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Description of variable rate basis

'

'

'LIBOR or lender's prime rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'lender's prime rate

Unsecured notes payable assumed in the business acquisition

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$25,000,000

'

'

'

'

'

Basis spread on variable rate (as a percent)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.00%

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations	'	'
Asset retirement obligations - beginning of year	$10,552	$6,715
Obligations incurred for wells drilled or on properties acquired	242	9,440
Obligations related to assets sold	'	-6,107
Accretion expense	1,065	504
Asset retirement obligations - end of year	$11,859	$10,552

Profits_Interests_Awards_Detai

Profits Interests Awards (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Profits Interests Awards	'
Stock compensation expense recognized	$365,280,000
Additional stock compensation to be recognized over the remaining service period	121,000,000
Profits interests awards	'
Profits Interests Awards	'
Stock compensation expense recognized	$364,957,000

StockBased_Compensation_Detail

Stock-Based Compensation (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Stock-Based Compensation	'
Number of stock-based compensation awards authorized	16,906,500
Number of shares available for future grant under the Plan	16,791,068
Stock-based compensation expense	'
Stock compensation expense recognized	$365,280
Profits interests awards	'
Stock-based compensation expense	'
Stock compensation expense recognized	364,957
Restricted stock	'
Stock-based compensation expense	'
Stock compensation expense recognized	219
Stock options	'
Stock-based compensation expense	'
Stock compensation expense recognized	$104

StockBased_Compensation_Detail1

Stock-Based Compensation (Details 2) (Restricted stock, USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Number of shares	'
Granted (in shares)	45,093
Total awarded and unvested at the end of the period (in shares)	45,093
Weighted average grant date fair value	'
Granted (in dollars per share)	$54.27
Total awarded and unvested at the end of the period (in dollars per share)	$54.27
Aggregate intrinsic value	'
Total awarded and unvested at the end of the period	$2,861
Vesting date, 2014	'
Additional disclosures	'
Number of awards (in shares)	20,818
Vesting date, 2015	'
Additional disclosures	'
Number of awards (in shares)	8,092
Vesting date, 2016	'
Additional disclosures	'
Number of awards (in shares)	8,092
Vesting date, 2017	'
Additional disclosures	'
Number of awards (in shares)	8,091

StockBased_Compensation_Detail2

Stock-Based Compensation (Details 3) (Stock options, USD $)	12 Months Ended
	Dec. 31, 2013
Stock options	'
Options granted (in shares)	70,339
Options exercised (in shares)	0
Outstanding at the end of the period (in shares)	70,339
Vested or expected to vest (in shares)	70,339
Weighted average exercise price	'
Options granted (in dollars per share)	$54.15
Outstanding at the end of the period (in dollars per share)	$54.15
Vested or expected to vest (in dollars per share)	$54.15
Weighted average remaining contractual life	'
Vested and expected to vest	'9 years 9 months 14 days
Exercisable	'9 years 9 months 14 days
Intrinsic Value	'
Vested and expected to vest	$653,000
Exercisable	653,000
Weighted-average assumptions used to calculate fair value of stock options granted	'
Dividend yield (as a percent)	0.00%
Volatility (as a percent)	35.00%
Risk-free interest rate (as a percent)	1.48%
Expected life	'6 years 2 months 1 day
Weighted average fair value of options granted (in dollars per share)	$20.20
Additional disclosures	'
Unrecognized stock-based compensation expense	$1,300,000
Weighted average period for recognizing unrecognized stock-based compensation expense	'4 years
Minimum	'
Stock-based compensation	'
Vesting period	'1 year
Maximum	'
Stock-based compensation	'
Vesting period	'4 years
Contractual life	'10 years

Financial_Instruments_Details

Financial Instruments (Details) (Recurring, Level 2 market data, USD $)	Dec. 31, 2013
In Billions, unless otherwise specified
Recurring | Level 2 market data	'
Financial Instruments	'
Fair value of senior notes	$1.90

Derivative_Instruments_Details

Derivative Instruments (Details)	Dec. 31, 2013	Dec. 31, 2012
	item	item
Interest rate swap agreements	'	'
Derivative Instruments	'	'
Number of derivative instruments held	0	0
Swaps | Natural gas | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	610,000	'
Swaps | Natural gas | Year ending December 31, 2015	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	540,000	'
Swaps | Natural gas | Year ending December 31, 2016	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	632,500	'
Swaps | Natural gas | Year ending December 31, 2017	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	740,000	'
Swaps | Natural gas | CGTAP-TCO | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	210,000	'
Weighted average index price	5.11	'
Swaps | Natural gas | CGTAP-TCO | Year ending December 31, 2015	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	130,000	'
Weighted average index price	4.93	'
Swaps | Natural gas | CGTAP-TCO | Year ending December 31, 2016	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	80,000	'
Weighted average index price	4.67	'
Swaps | Natural gas | CGTAP-TCO | Year ending December 31, 2017	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	20,000	'
Weighted average index price	4.02	'
Swaps | Natural gas | Dominion South | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	160,000	'
Weighted average index price	5.15	'
Swaps | Natural gas | Dominion South | Year ending December 31, 2015	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	230,000	'
Weighted average index price	5.6	'
Swaps | Natural gas | Dominion South | Year ending December 31, 2016	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	272,500	'
Weighted average index price	5.35	'
Swaps | Natural gas | NYMEX | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	230,000	'
Weighted average index price	3.99	'
Swaps | Natural gas | NYMEX | Year ending December 31, 2015	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	140,000	'
Weighted average index price	4.08	'
Swaps | Natural gas | NYMEX | Year ending December 31, 2016	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	110,000	'
Weighted average index price	4.18	'
Swaps | Natural gas | NYMEX | Year ending December 31, 2017	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	230,000	'
Weighted average index price	4.43	'
Swaps | Natural gas | NYMEX | Year ending December 31, 2018	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	620,000	'
Weighted average index price	4.66	'
Swaps | Natural gas | CGLA | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	10,000	'
Weighted average index price	3.87	'
Swaps | Natural gas | CGLA | Year ending December 31, 2015	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	40,000	'
Weighted average index price	4	'
Swaps | Natural gas | CGLA | Year ending December 31, 2016	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	170,000	'
Weighted average index price	4.09	'
Swaps | Natural gas | CGLA | Year ending December 31, 2017	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	420,000	'
Weighted average index price	4.27	'
Swaps | Natural gas | CGLA | Year ending December 31, 2019	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	277,500	'
Weighted average index price	4.51	'
Swaps | Natural gas | NYMEX-WTI | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Weighted average index price	96.53	'
Swaps | Natural gas | CCG | Year ending December 31, 2017	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	70,000	'
Weighted average index price	4.57	'
Swaps | Oil | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	3,000	'
Swaps | Oil | NYMEX-WTI | Year ending December 31, 2014	'	'
Derivative Instruments	'	'
Notional amount (MMBtu/Bbls per day)	3,000	'

Derivative_Instruments_Details1

Derivative Instruments (Details 2) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair value of derivative instruments	'	'
Current portion of fair value of derivative assets	$183,000	$160,579
Noncurrent portion of fair value of derivative assets	677,780	371,436
Current portion of fair value of derivative liability	646	'
Commodity contracts	'	'
Fair value of derivative instruments	'	'
Total asset derivatives	860,780	532,015
Derivatives not designated as hedges for accounting purposes | Commodity contracts	'	'
Fair value of derivative instruments	'	'
Current portion of fair value of derivative assets	183,000	160,579
Noncurrent portion of fair value of derivative assets	677,780	371,436
Total asset derivatives	860,780	532,015
Current portion of fair value of derivative liability	646	'
Net derivatives	$860,134	$532,015
Derivatives designated as hedges for accounting purposes	'	'
Fair value of derivative instruments	'	'
Number of derivative instruments held	0	'

Derivative_Instruments_Details2

Derivative Instruments (Details 3) (Commodity derivative, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Commodity derivative	'	'
Commodity derivative assets	'	'
Gross amounts of recognized assets	$887,034	$597,359
Gross amounts offset on balance sheet	-26,254	-65,344
Total asset derivatives	860,780	532,015
Commodity derivative liabilities	'	'
Gross amounts offset on balance sheet	-646	'
Net amounts of assets (liabilities) on balance sheet	($646)	'

Derivative_Instruments_Details3

Derivative Instruments (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of realized and unrealized gains (losses) on derivative instruments	'	'	'
Commodity derivative fair value gains	$491,689,000	$225,904,000	$676,194,000
Interest rate derivative fair value loss	'	'	-94,000
Net derivative fair value gains	491,689,000	225,904,000	676,100,000
Revenue	'	'	'
Summary of realized and unrealized gains (losses) on derivative instruments	'	'	'
Commodity derivative fair value gains	491,689,000	179,546,000	496,064,000
Discontinued operations	'	'	'
Summary of realized and unrealized gains (losses) on derivative instruments	'	'	'
Commodity derivative fair value gains	'	46,358,000	180,130,000
Other expense	'	'	'
Summary of realized and unrealized gains (losses) on derivative instruments	'	'	'
Interest rate derivative fair value loss	'	'	($94,000)

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income tax expense from continuing operations	'	'	'
Current income tax expense (benefit)	($4,000)	$15,000	'
Deferred income tax expense	190,210	106,229	185,297
Total income tax expense from continuing operations	186,210	121,229	185,297
U.S. Statutory federal income tax rate (as a percent)	35.00%	35.00%	35.00%
Reconciliation of income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate to consolidated income	'	'	'
Federal income tax expense	56,708	121,276	159,770
State income tax expense , net of federal benefit	21,429	4,761	23,593
Nondeductible stock compensation	127,736	'	'
Change in valuation allowance	-20,919	-4,872	-934
Other	1,256	64	2,868
Total income tax expense from continuing operations	186,210	121,229	185,297
Income tax expense (benefit) allocated to continuing and discontinued operations	'	'	'
Continuing operations	186,210	121,229	185,297
Discontinued operations and sale of discontinued operations	3,249	-272,553	45,155
Total income tax expense (benefit)	189,459	-151,324	230,452
Deferred tax assets:	'	'	'
Net operating loss carryforwards	449,961	417,385	'
Capital loss carryforwards	'	5,367	'
Minimum tax credit carryforward	11,000	15,000	'
Other	5,373	5,006	'
Total deferred tax assets	466,334	442,758	'
Valuation allowance	-26,759	-47,678	'
Net deferred tax assets	439,575	395,080	'
Deferred tax liabilities:	'	'	'
Unrealized gains on derivative instruments	328,534	206,937	'
Oil and gas properties	458,812	342,455	'
Total deferred tax liabilities	787,346	549,392	'
Net deferred tax liabilities	($347,771)	($154,312)	'

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2013
Income Taxes	'
Unrecognized tax benefits impacting effective tax rate	$11,000,000
Interest or penalties that have been accrued on unrecognized tax benefits	500,000
Unrecognized tax benefits	'
Balance at beginning of year	15,000,000
Revised estimate of unrecognized tax position	-4,000,000
Balance at end of year	11,000,000
U.S Federal	'
Income Taxes	'
Net operating loss carryforward	1,200,000,000
State	'
Income Taxes	'
Net operating loss carryforward	$1,100,000,000

Commitments_Details

Commitments (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Future minimum payments	'	'	'
2014	$458.10	'	'
2015	416.6	'	'
2016	374.5	'	'
2017	354.1	'	'
2018	349.6	'	'
Thereafter	1,853.10	'	'
Total	3,806	'	'
Firm transportation	'	'	'
Future minimum payments	'	'	'
2014	120.5	'	'
2015	159.5	'	'
2016	160.9	'	'
2017	158.4	'	'
2018	159	'	'
Thereafter	1,002.90	'	'
Total	1,761.20	'	'
Gas processing, gathering and compression	'	'	'
Future minimum payments	'	'	'
2014	182.8	'	'
2015	184.7	'	'
2016	196.1	'	'
2017	192.5	'	'
2018	189.1	'	'
Thereafter	836.1	'	'
Total	1,781.30	'	'
Drilling rigs and frac Services	'	'	'
Future minimum payments	'	'	'
2014	150.9	'	'
2015	68.3	'	'
2016	13.7	'	'
Total	232.9	'	'
Commitments	'	'	'
Rigs committed	20	'	'
Office and equipment	'	'	'
Future minimum payments	'	'	'
2014	3.9	'	'
2015	4.1	'	'
2016	3.8	'	'
2017	3.2	'	'
2018	1.5	'	'
Thereafter	14.1	'	'
Total	30.6	'	'
Commitments	'	'	'
Rental expense under operating leases	$1.80	$1.10	$1

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	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, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	$480,014	$384,522	$387,144	$61,454	$235,090	($92,038)	$38,925	$553,741	$1,313,134	$735,718	$691,353
Depletion, depreciation, and amortization	'	'	'	'	'	'	'	'	233,876	102,026	55,716
Interest expense	'	'	'	'	'	'	'	'	136,617	97,510	74,404
Income tax expense	'	'	'	'	'	'	'	'	186,210	121,229	185,297
Operating income	-81,318	222,608	248,386	-48,469	124,013	-166,878	-23,456	510,336	341,207	444,015	530,983
Segment assets	6,613,581	'	'	'	3,618,793	'	'	'	6,613,581	3,618,793	'
Capital expenditures for segment assets	'	'	'	'	'	'	'	'	2,671,573	'	'
Exploration and production	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	1,313,134	'	'
Gathering and compression	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	22,363	'	'
Fresh Water Distribution	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	35,871	'	'
Operating segments | Exploration and production	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	1,313,134	'	'
Depletion, depreciation, and amortization	'	'	'	'	'	'	'	'	220,857	'	'
Interest expense	'	'	'	'	'	'	'	'	136,453	'	'
Income tax expense	'	'	'	'	'	'	'	'	186,210	'	'
Operating income	'	'	'	'	'	'	'	'	335,901	'	'
Segment assets	6,580,282	'	'	'	'	'	'	'	6,580,282	'	'
Capital expenditures for segment assets	'	'	'	'	'	'	'	'	2,110,358	'	'
Operating segments | Gathering and compression	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	22,363	'	'
Depletion, depreciation, and amortization	'	'	'	'	'	'	'	'	11,346	'	'
Interest expense	'	'	'	'	'	'	'	'	155	'	'
Operating income	'	'	'	'	'	'	'	'	8,938	'	'
Segment assets	561,855	'	'	'	'	'	'	'	561,855	'	'
Capital expenditures for segment assets	'	'	'	'	'	'	'	'	389,453	'	'
Operating segments | Fresh Water Distribution	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	35,871	'	'
Depletion, depreciation, and amortization	'	'	'	'	'	'	'	'	2,773	'	'
Interest expense	'	'	'	'	'	'	'	'	9	'	'
Operating income	'	'	'	'	'	'	'	'	27,296	'	'
Segment assets	230,247	'	'	'	'	'	'	'	230,247	'	'
Capital expenditures for segment assets	'	'	'	'	'	'	'	'	203,790	'	'
Elimination of intersegment transaction	'	'	'	'	'	'	'	'	'	'	'
Operating results and assets of reportable segments	'	'	'	'	'	'	'	'	'	'	'
Sales and revenues	'	'	'	'	'	'	'	'	-58,234	'	'
Depletion, depreciation, and amortization	'	'	'	'	'	'	'	'	-1,100	'	'
Operating income	'	'	'	'	'	'	'	'	-30,928	'	'
Segment assets	-758,803	'	'	'	'	'	'	'	-758,803	'	'
Capital expenditures for segment assets	'	'	'	'	'	'	'	'	($32,028)	'	'

Subsidiary_Guarantor_Details

Subsidiary Guarantor (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Current assets:	'	'	'	'
Cash and cash equivalents	$17,487	$18,989	$3,343	$8,988
Other	2,975	22,518	'	'
Total current assets	333,564	274,606	'	'
Property and equipment, net	5,559,656	2,937,473	'	'
Other long-term assets	720,361	'	'	'
Investment in subsidiary	1	'	'	'
Total assets	6,613,581	3,618,793	'	'
Liabilities and Stockholders' Equity	'	'	'	'
Current liabilities	622,229	376,296	'	'
Long-term debt	2,078,999	1,444,058	'	'
Other long-term liabilities	313,693	'	'	'
Total liabilities	3,014,921	1,945,056	'	'
Total equity	3,598,660	1,673,737	1,958,806	1,594,987
Total liabilities and equity	6,613,581	3,618,793	'	'
Reportable legal entity | Parent Company	'	'	'	'
Current assets:	'	'	'	'
Cash and cash equivalents	17,487	'	'	'
Other	316,077	'	'	'
Total current assets	333,564	'	'	'
Property and equipment, net	5,559,656	'	'	'
Other long-term assets	720,361	'	'	'
Investment in subsidiary	1	'	'	'
Total assets	6,613,582	'	'	'
Liabilities and Stockholders' Equity	'	'	'	'
Current liabilities	622,229	'	'	'
Long-term debt	2,078,999	'	'	'
Other long-term liabilities	313,693	'	'	'
Due to subsidiary	1	'	'	'
Total liabilities	3,014,922	'	'	'
Total equity	3,598,660	'	'	'
Total liabilities and equity	6,613,582	'	'	'
Reportable legal entity | Guarantor Subsidiary	'	'	'	'
Current assets:	'	'	'	'
Other	1	'	'	'
Total current assets	1	'	'	'
Total assets	1	'	'	'
Liabilities and Stockholders' Equity	'	'	'	'
Total equity	1	'	'	'
Total liabilities and equity	1	'	'	'
Eliminations	'	'	'	'
Current assets:	'	'	'	'
Other	-1	'	'	'
Total current assets	-1	'	'	'
Investment in subsidiary	-1	'	'	'
Total assets	-2	'	'	'
Liabilities and Stockholders' Equity	'	'	'	'
Due to subsidiary	-1	'	'	'
Total liabilities	-1	'	'	'
Total equity	-1	'	'	'
Total liabilities and equity	($2)	'	'	'

Quarterly_Financial_Informatio2

Quarterly Financial Information (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	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, 2013	Dec. 31, 2012	Dec. 31, 2011
									Mcfe	Mcfe	Mcfe
Quarterly Financial Information (Unaudited)	'	'	'	'	'	'	'	'	'	'	'
Total operating revenues	$480,014	$384,522	$387,144	$61,454	$235,090	($92,038)	$38,925	$553,741	$1,313,134	$735,718	$691,353
Total operating expenses	561,332	161,914	138,758	109,923	111,077	74,840	62,381	43,405	971,927	291,703	160,370
Operating income (loss)	-81,318	222,608	248,386	-48,469	124,013	-166,878	-23,456	510,336	341,207	444,015	530,983
Income from continuing operations	-225,177	117,794	131,193	-47,997	84,845	-113,887	-33,237	287,555	-24,187	225,276	271,188
Income (loss) from discontinued operations	2,157	3,100	'	'	-91,880	-13,791	-444,850	40,176	5,257	-510,345	121,490
Net income (loss) and comprehensive income (loss)	($223,020)	$120,894	$131,193	($47,997)	($7,035)	($127,678)	($478,087)	$327,731	($18,930)	($285,069)	$392,678
Earnings (loss) per common share - basic:	'	'	'	'	'	'	'	'	'	'	'
Continuing operations (in dollars per share)	($0.86)	$0.45	$0.50	($0.18)	$0.32	($0.44)	($0.12)	$1.10	($0.09)	$0.86	$1.04
Discontinued operations (in dollars per share)	$0.01	$0.01	'	'	($0.35)	($0.05)	($1.70)	$0.15	$0.02	($1.95)	$0.46
Total (in dollars per share)	($0.85)	$0.46	$0.50	($0.18)	($0.03)	($0.49)	($1.82)	$1.25	($0.07)	($1.09)	$1.50
Earnings (loss) per share - diluted:	'	'	'	'	'	'	'	'	'	'	'
Continuing operations (in dollars per share)	($0.86)	$0.45	$0.50	($0.18)	$0.32	($0.44)	($0.12)	$1.10	($0.09)	$0.86	$1.04
Discontinued operations (in dollars per share)	$0.01	$0.01	'	'	($0.35)	($0.05)	($1.70)	$0.15	$0.02	($1.95)	$0.46
Total (in dollars per share)	($0.85)	$0.46	$0.50	($0.18)	($0.03)	($0.49)	($1.82)	$1.25	($0.07)	($1.09)	$1.50
Reduction of proved reserves resulted from downward price revisions	'	'	'	'	'	'	'	'	692,000,000	102,000,000	6,000,000
Oil and gas reserves	'	'	'	'	'	'	'	'	'	'	'
Extensions, discoveries and other additions	'	'	'	'	'	'	'	'	3,682,000,000	1,951,000,000	1,982,000,000
NGLs and oil	'	'	'	'	'	'	'	'	'	'	'
Oil and gas reserves	'	'	'	'	'	'	'	'	'	'	'
Extensions, discoveries and other additions	'	'	'	'	'	'	'	'	'	709,000,000	'
Initial period to drill well	'	'	'	'	'	'	'	'	'5 years	'	'

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Costs Relating to Oil and Gas Producing Activities	'	'	'
Proved properties	$3,621,672	$1,682,297	'
Unproved properties	1,513,136	1,243,237	'
Total	5,134,808	2,925,534	'
Accumulated depreciation and depletion	-383,921	-158,210	'
Net capitalized costs	4,750,887	2,767,324	'
Costs Incurred in Certain Oil and Gas Activities	'	'	'
Proved property	15,300	10,254	105,405
Unproved property	440,825	687,403	195,131
Development costs	780,583	678,276	432,147
Exploration costs	835,382	158,074	95,563
Total costs incurred	2,072,090	1,534,007	828,246
Results of Operations for Oil and Gas Producing Activities	'	'	'
Revenues	821,445	390,378	391,994
Operating expenses:	'	'	'
Production expenses	278,348	185,505	136,635
Exploration expenses	22,272	15,339	9,876
Depreciation and depletion	219,830	181,664	164,011
Impairment of unproved properties	10,928	13,032	11,051
Results of operations before income tax expense (benefit)	290,067	-5,162	70,421
Income tax (expense) benefit	-110,805	2,008	-26,056
Results of operations	$179,262	($3,154)	$44,365

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcfe	Mcfe	Mcfe
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	'	'	'
Period of average prices considered to calculate estimated proved reserves	'12 months	'	'
Scheduled drilling period for proved undeveloped reserves	'5 years	'	'
Proved developed and undeveloped reserves:	'	'	'
Balance at the beginning of the period	4,929,000,000	5,017,000,000	3,231,000,000
Revisions	-788,000,000	222,000,000	-172,000,000
Extensions, discoveries and other additions	3,682,000,000	1,951,000,000	1,982,000,000
Production	-191,000,000	-87,000,000	-89,000,000
Purchase of reserves	'	'	66,000,000
Sale of reserves in place	'	-2,174,000,000	-1,000,000
Balance at the end of the period	7,632,000,000	4,929,000,000	5,017,000,000
Oil and Gas Reserves	'	'	'
Proved developed reserves	2,022,000,000	1,047,000,000	844,000,000
Proved undeveloped reserves	5,610,000,000	3,882,000,000	4,173,000,000
Minimum	'	'	'
Oil and gas reserves	'	'	'
Number of offset locations away from productive wells for proved undeveloped reserves	1	'	'
Natural gas	'	'	'
Proved developed and undeveloped reserves:	'	'	'
Balance at the beginning of the period	3,694,000	3,931,000	2,543,000
Revisions	152,000	198,000	-223,000
Extensions, discoveries and other additions	3,084,000	1,242,000	1,644,000
Production	-177,000	-87,000	-84,000
Purchase of reserves	'	'	52,000
Sale of reserves in place	'	-1,590,000	-1,000
Balance at the end of the period	6,753,000	3,694,000	3,931,000
Oil and Gas Reserves	'	'	'
Proved developed reserves	1,818,000	828,000	718,000
Proved undeveloped reserves	4,936,000	2,866,000	3,213,000
NGLS	'	'	'
Proved developed and undeveloped reserves:	'	'	'
Balance at the beginning of the period	203	164	104
Revisions	-140	4	2
Extensions, discoveries and other additions	76	115	57
Production	-2	'	-1
Purchase of reserves	'	'	2
Sale of reserves in place	'	-80	'
Balance at the end of the period	137	203	164
Oil and Gas Reserves	'	'	'
Proved developed reserves	33	36	19
Proved undeveloped reserves	105	167	145
Oil and condensate	'	'	'
Proved developed and undeveloped reserves:	'	'	'
Balance at the beginning of the period	3	17	10
Revisions	'	'	7
Extensions, discoveries and other additions	7	3	'
Sale of reserves in place	'	-17	'
Balance at the end of the period	10	3	17
Oil and Gas Reserves	'	'	'
Proved developed reserves	2	1	2
Proved undeveloped reserves	8	2	15

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcfe	Mcfe	Mcfe
Oil and gas reserves	'	'	'
Extensions, discoveries and other additions	3,682,000,000	1,951,000,000	1,982,000,000
Decrease in proved reserves due to performance revisions	'	'	346,000,000
Reduction of proved reserves resulted from downward price revisions	692,000,000	102,000,000	6,000,000
Sales of proved reserves	'	-2,174,000,000	-1,000,000
Increase in proved reserves due to performance revisions	'	324,000,000	'
Annual net cash inflows	'	'	'
Period of unweighted first day of the month average prices used to compute future cash inflows	'12 months	'	'
Future cash inflows	$30,113	$12,151	$20,046
Future production costs	-5,967	-1,660	-3,491
Future development costs	-5,349	-3,270	-5,085
Future net cash flows before income tax	18,797	7,221	11,470
Future income tax expense	-5,308	-1,603	-3,287
Future net cash flows	13,489	5,618	8,183
10% annual discount for estimated timing of cash flows	-8,979	-4,017	-5,713
Standardized measure of discounted future net cash flows	$4,510	$1,601	$2,470
NGLs and oil	'	'	'
Oil and gas reserves	'	'	'
Extensions, discoveries and other additions	'	709,000,000	'
Initial period to drill well	'5 years	'	'
Arkoma Basin, Oklahoma	'	'	'
Oil and gas reserves	'	'	'
Extensions, discoveries and other additions	'	'	93,000,000
Piceance Basin	'	'	'
Oil and gas reserves	'	'	'
Extensions, discoveries and other additions	'	'	61,000,000
Appalachia Basin, Pennsylvania and West Virginia	'	'	'
Oil and gas reserves	'	'	'
Extensions, discoveries and other additions	'	'	1,816,000,000
Increase in proved reserves due to execution of the gas processing agreements	'	'	180,000,000
Other areas	'	'	'
Oil and gas reserves	'	'	'
Extensions, discoveries and other additions	'	'	12,000,000
Arkoma and Piceance Basin	'	'	'
Oil and gas reserves	'	'	'
Sales of proved reserves	'	2,174,000,000	'

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Details 4) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in Standardized Measure of Discounted Future Net Cash Flow	'	'	'
Sales of oil and gas, net of productions costs	($761)	($147)	($255)
Net changes in prices and production costs	1,061	-1,631	215
Development costs incurred during the period	384	296	247
Net changes in future development costs	-181	-92	-106
Extensions, discoveries and other additions	3,441	813	1,684
Acquisitions	2	'	51
Divestitures	'	-1,277	'
Revisions of previous quantity estimates	-270	88	-182
Accretion of discount	192	322	147
Net change in income taxes	-1,165	653	-605
Other changes	206	106	177
Net increase (decrease)	2,909	-869	1,373
Beginning of period	1,601	2,470	1,097
End of period	$4,510	$1,601	$2,470
Arkoma Basin, Oklahoma	'	'	'
Supplemental Information on Oil and Gas Producing Activities	'	'	'
Weighted average price of equivalent reserves (in dollar per share)	'	'	$3.90
Piceance Basin	'	'	'
Supplemental Information on Oil and Gas Producing Activities	'	'	'
Weighted average price of equivalent reserves (in dollar per share)	'	'	$3.84
Appalachia Basin, Pennsylvania and West Virginia	'	'	'
Supplemental Information on Oil and Gas Producing Activities	'	'	'
Weighted average price of equivalent reserves (in dollar per share)	$3.95	$2.78	$4.16