Cimarex Resolute (REN) 10-K 5 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 27, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	REN
Entity Registrant Name	Resolute Energy Corp
Entity Central Index Key	1469510
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		77,612,287
Entity Public Float			$463.60

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$4,352	$19
Accounts receivable	57,909	94,358
Deferred income taxes	0	8,330
Derivative instruments	72,753	1,378
Prepaid expenses and other current assets	1,858	1,152
Total current assets	136,872	105,237
Property and equipment, at cost:
Oil and gas properties, full cost method of accounting, Unproved	270,375	274,420
Oil and gas properties, full cost method of accounting, Proved	1,706,847	1,544,942
Other property and equipment	9,994	8,069
Accumulated depletion, depreciation and amortization	-744,220	-494,642
Net property and equipment	1,242,996	1,332,789
Other assets:
Restricted cash	19,858	18,219
Deferred income taxes	869	0
Derivative instruments	39,799	0
Deferred financing costs	14,525	12,265
Other assets	182	299
Total assets	1,455,101	1,468,809
Current liabilities:
Accounts payable	25,781	32,601
Accrued expenses	65,799	81,478
Accrued interest payable	5,739	5,739
Asset retirement obligations	327	1,825
Deferred income taxes	23,223	0
Derivative instruments	0	11,955
Total current liabilities	120,869	133,598
Long term liabilities:
Revolving credit facility	235,000	335,000
Senior notes, net of accumulated premium amortization of $414 and $204 at December 31, 2014 and 2013, respectively	401,461	401,671
Secured term loan facility, net of original issue discount of $10,500 at December 31, 2014	139,500	0
Asset retirement obligations	31,013	30,164
Deferred income taxes	0	34,824
Other long term liabilities	640	0
Total liabilities	928,483	935,257
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued or outstanding
Common stock, $0.0001 par value; 225,000,000 shares authorized; issued and outstanding 77,634,737 and 76,228,055 shares at December 31, 2014 and 2013, respectively	8	8
Additional paid-in capital	646,738	631,822
Accumulated deficit	-120,128	-98,278
Total stockholders’ equity	526,618	533,552
Total liabilities and stockholders’ equity	$1,455,101	$1,468,809

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement Of Financial Position [Abstract]
Senior notes, accumulated premium amortization	$414	$204
Term loan facility, original issue discount	$10,500
Preferred stock, par value	$0.00	$0.00
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0
Common stock, par value	$0.00	$0.00
Common stock, shares authorized	225,000,000	225,000,000
Common stock, issued	77,634,737	76,228,055
Common stock, outstanding	77,634,737	76,228,055

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue:
Oil	$293,970	$321,047	$240,444
Gas	26,254	21,444	16,289
Natural gas liquids	9,147	7,288	1,535
Total revenue	329,371	349,779	258,268
Operating expenses:
Lease operating	112,683	103,276	79,922
Production and ad valorem taxes	37,216	40,402	35,716
Depletion, depreciation, amortization, and asset retirement obligation accretion	132,154	116,344	78,414
Impairment of proved oil and gas properties	120,000	188,000	0
General and administrative	39,992	35,625	24,032
Total operating expenses	442,045	483,647	218,084
Income (loss) from operations	-112,674	-133,868	40,184
Other income (expense):
Interest expense, net	-31,489	-29,302	-15,523
Commodity derivative instruments gain (loss)	118,141	-15,336	5,176
Other income	32	21	20
Total other income (expense)	86,684	-44,617	-10,327
Income (loss) before income taxes	-25,990	-178,485	29,857
Income tax benefit (expense)	4,140	64,679	-11,881
Net income (loss)	($21,850)	($113,806)	$17,976
Net income (loss) per common share:
Basic and diluted	($0.30)	($1.67)	$0.30
Weighted average common shares outstanding:
Basic	73,798	68,260	59,424
Diluted	73,798	68,260	59,452

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders' Equity (USD $)	Total	Common Stock	Additional Paid-in Capital	Retained Earnings/Accumulated (Deficit)
In Thousands
Beginning Balance at Dec. 31, 2011	$515,825	$6	$518,267	($2,448)
Beginning Balance (in shares) at Dec. 31, 2011		60,947
Issuance of stock, restricted stock and share-based compensation	9,508	0	9,508	0
Issuance of stock, restricted stock and share-based compensation (in shares)		1,127
Redemption of restricted stock for employee income tax, restricted stock forfeitures and expirations	-1,126	0	-1,126	0
Redemption of restricted stock for employee income tax, restricted stock forfeitures and expirations (in shares)		-201
Retirement of public warrants	-9,999	0	-9,999	0
Net (loss) income	17,976	0	0	17,976
Ending Balance at Dec. 31, 2012	532,184	6	516,650	15,528
Ending Balance (in shares) at Dec. 31, 2012		61,873
Issuance of stock, restricted stock and share-based compensation	14,965	1	14,964	0
Issuance of stock, restricted stock and share-based compensation (in shares)		1,925
Redemption of restricted stock for employee income tax, restricted stock forfeitures and expirations	-1,551	0	-1,551	0
Redemption of restricted stock for employee income tax, restricted stock forfeitures and expirations (in shares)		-820
Issuance of stock, net of underwriters discounts and commissions	101,760	1	101,759	0
Issuance of stock, net of underwriters discounts and commissions (in shares)		13,250
Net (loss) income	-113,806	0	0	-113,806
Ending Balance at Dec. 31, 2013	533,552	8	631,822	-98,278
Ending Balance (in shares) at Dec. 31, 2013		76,228
Issuance of stock, restricted stock and share-based compensation	16,651	0	16,651	0
Issuance of stock, restricted stock and share-based compensation (in shares)		2,084
Redemption of restricted stock for employee income tax, restricted stock forfeitures and expirations	-1,735	0	-1,735	0
Redemption of restricted stock for employee income tax, restricted stock forfeitures and expirations (in shares)		-677
Net (loss) income	-21,850	0	0	-21,850
Ending Balance at Dec. 31, 2014	$526,618	$8	$646,738	($120,128)
Ending Balance (in shares) at Dec. 31, 2014		77,635

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income (loss)	($21,850)	($113,806)	$17,976
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and asset retirement obligation accretion	132,154	116,344	78,414
Impairment of proved oil and gas properties	120,000	188,000	0
Amortization of deferred financing costs and senior notes premium	2,337	2,481	1,691
Share-based compensation	16,331	14,924	9,399
Commodity derivative instruments (gain) loss	-118,141	15,336	-5,176
Commodity derivative settlements	-4,988	-35,812	-22,920
Deferred income taxes (benefit)	-4,140	-64,663	11,865
Change in operating assets and liabilities:
Accounts receivable	36,768	-15,961	-15,317
Other current assets	-706	539	138
Accounts payable and accrued expenses	-14,297	25,905	-4,859
Accrued interest payable	0	41	5,560
Net cash provided by operating activities	143,468	133,328	76,771
Investing activities:
Oil and gas exploration and development expenditures	-183,565	-261,758	-212,241
Purchase of oil and gas properties	0	-257,948	-286,636
Proceeds from sale of oil and gas properties and other	11,122	121,361	49,692
Purchase of other property and equipment	-1,925	-2,467	-1,532
Restricted cash	-1,639	203	-1,821
Other	114	-4,909	5,091
Net cash used in investing activities	-175,893	-405,518	-447,447
Financing activities:
Proceeds from bank borrowings	433,500	638,000	649,600
Repayments of bank borrowings	-533,500	-465,000	-657,600
Proceeds from issuance of term loans	139,500	0	401,875
Redemption of restricted stock for employee income taxes	-1,735	-1,551	-1,126
Payment of financing costs	-1,007	-1,934	-12,275
Proceeds from issuance of common stock, net of underwriters discounts and commissions	0	101,760	0
Retirement of public warrants	0	0	-9,999
Net cash provided by financing activities	36,758	271,275	370,475
Net increase (decrease) in cash and cash equivalents	4,333	-915	-201
Cash and cash equivalents at beginning of period	19	934	1,135
Cash and cash equivalents at end of period	4,352	19	934
Cash paid during the period for:
Interest, net of amounts capitalized	31,890	29,280	10,051
Income taxes	0	0	8
Supplemental schedule of non-cash investing and financing activities:
Capital expenditures financed through current liabilities	17,651	30,069	39,008
Increase (decrease) to asset retirement obligations	-2,012	11,421	315
Asset retirement obligations assumed	0	1,659	2,557
Asset retirement obligations sold	$157	$723	$0

Organization_and_Nature_of_Bus

Organization and Nature of Business	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Organization and Nature of Business	Note 1 — Organization and Nature of Business
	Resolute Energy Corporation (“Resolute” or the “Company”), is an independent oil and gas company engaged in the exploitation, development, exploration for and acquisition of oil and gas properties. The Company’s asset base in comprised primarily of properties in Aneth Field located in the Paradox Basin in southeast Utah (the “Aneth Field Properties” or “Aneth Field”), the Permian Basin in west Texas and southeast New Mexico and the Powder River and Big Horn Basins in Wyoming. The Company conducts all of its activities in the United States of America.

Basis_of_Presentation_and_Summ

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	Note 2 — Basis of Presentation and Summary of Significant Accounting Policies
	Basis of Presentation
	The consolidated financial statements include Resolute and its subsidiaries, and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All significant intercompany transactions have been eliminated upon consolidation.
	In connection with the preparation of the consolidated financial statements, Resolute evaluated subsequent events that occurred after the balance sheet date, through the date of filing.
	Assumptions, Judgments and Estimates
	The preparation of the consolidated financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously established.
	Significant estimates with regard to the consolidated financial statements include proved oil and gas reserve volumes and the related present value of estimated future net cash flows used in the ceiling test applied to capitalized oil and gas properties; asset retirement obligations; valuation of derivative assets and liabilities; the estimated fair value and allocation of the purchase price related to business combinations; share-based compensation expense; depletion depreciation, and amortization; accrued liabilities; revenue and related receivables and income taxes.
	Fair Value of Financial Instruments
	The carrying amount of the majority of Resolute’s financial instruments, namely cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value because of the short-term nature of these instruments. The revolving credit facility (see Note 5) has a recorded value that approximates its fair market value while the fair value of the $400 million in principal senior notes due May 1, 2020 (the “Senior Notes” or the “Notes”) and the $150 million in the second lien secured term loan due March 2018 (the “Secured Term Loan Facility”) are based on data from independent market makers or price received at measurement date. The fair value of derivative instruments (see Note 10) is estimated based on market conditions in effect at the end of each reporting period.
	Industry Segment and Geographic Information
	Resolute conducts oil, gas and natural gas liquids (“NGL”) exploration and production operations in one segment. All of Resolute’s operations and assets are located in the United States, and all of its revenue is attributable to domestic customers. Resolute considers gathering, processing and marketing functions as supportive of its oil and gas producing activities, and accordingly, they are not reported as separate segments.
	Cash and Cash Equivalents
	Resolute considers all highly liquid investments with original maturities of three months or less at the date of purchase to be cash equivalents. Resolute periodically maintains cash and cash equivalents in bank deposit accounts and money market funds which may be in excess of federally insured amounts. Resolute has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
	Accounts Receivable
	The Company’s accounts receivable consist of the following for the periods indicated (in thousands):
		December 31,
		2014		2013
	Trade receivables	$	51,166	$	92,959
	Derivative receivables		6,638		866
	Other receivables		105		533
	Total accounts receivable	$	57,909	$	94,358
	The Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are due within fifteen days and are collected in less than two months, and the Company has had minimal bad debts.
	The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. As of December 31, 2014 and 2013, the Company had no allowance for doubtful accounts recorded.
	Deferred Financing Costs
	Deferred financing costs are amortized over the estimated life of the related obligation. The Company incurred $4.8 million in deferred financing costs in 2014, $1.9 million in 2013 and $12.3 million in 2012, and amortized $2.5 million, $2.7 million and $1.7 million to interest expense during 2014, 2013 and 2012, respectively.
	Capitalized Interest
	Interest is capitalized when associated with significant investments in unproved properties and major development projects that are excluded from current depletion, depreciation and amortization calculations and on which exploration or development activities are in progress. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of qualified costs. Costs excluded from the depletion, depreciation and amortization calculations are classified as unproved properties along with any associated capitalized interest. Capitalized interest totaled $14.9 million, $15.9 million and $4.7 million during 2014, 2013 and 2012, respectively.
	Concentration of Credit Risk
	Financial instruments that potentially subject Resolute to concentrations of credit risk consist primarily of trade, production and derivative settlement receivables. Resolute derived approximately 62% and 14% of its total 2014 revenue from Western Refining, Inc. (“Western”) and Plains Marketing LP, respectively; 61% and 15% of its total 2013 revenue from Western and Plains Marketing LP, respectively and 78% of its total 2012 revenue from Western. If Resolute was compelled to sell its oil to an alternative market, costs associated with the transportation of its production may increase, and such increase could materially and negatively affect its operations. The concentration of credit risk in the oil and gas industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements where appropriate. Commodity derivative contracts expose Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, all of which participate in Resolute’s Revolving Credit Facility (see Note 5).
	Oil and Gas Properties
	The Company uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, improved recovery systems and a portion of general and administrative and operating expenses are capitalized on a country wide basis (the “Cost Center”).
	Resolute conducts tertiary recovery projects on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Under the full cost method, all development costs are capitalized at the time incurred. Development costs include charges associated with access to and preparation of well locations, drilling and equipping development wells, test wells, and service wells including injection wells, and acquiring, constructing, and installing production facilities and providing for improved recovery systems. Improved recovery systems include all related facility development costs and the cost of the acquisition of tertiary injectants, primarily purchased carbon dioxide (“CO2”). The development costs related to CO2 purchases are incurred solely for the purpose of gaining access to incremental reserves not otherwise recoverable. The accumulation of injected CO2, in combination with additional purchased and recycled CO2, provides future economic value over the life of the project.
	In contrast, other costs related to the daily operation of the improved recovery systems are considered production costs and are expensed as incurred. These costs include, but are not limited to, compression, electricity, separation, re-injection of recovered CO2 and water and reservoir pressure maintenance.
	Capitalized general and administrative and operating costs include salaries, employee benefits, costs of consulting services and other specifically identifiable capital costs and do not include costs related to production operations, general corporate overhead or similar activities. Resolute capitalized general and administrative and operating costs related to its acquisition, exploration and development activities of $9.8 million during 2014, $8.4 million during 2013 and $6.0 million during 2012.
	Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. The Company’s investments in unproved properties are related to exploration plays in the Permian Basin in Texas and southeast New Mexico. The Company expects to evaluate these locations for the existence of proved reserves in the next 1 to 3 years, although volatility in commodity prices may impact the timing of the evaluation. Unproved properties are assessed at least annually to determine whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized.
	No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of the Company’s oil and gas properties and the gain or loss significantly alters the relationship between the capitalized costs and proved reserves of the cost center.
	Depletion of oil and gas properties is computed on the unit-of-production method based on proved reserves. Depletable costs include estimates of asset retirement obligations and future development costs of proved reserves, including, but not limited to, costs to drill and equip development wells, construct and install production and processing facilities, and improved recovery systems, including the cost of required future CO2 purchases.
	Pursuant to full cost accounting rules, accounting rules require Resolute to perform a quarterly “ceiling test” calculation to test its oil and gas properties for possible impairment. The primary components impacting the calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. If the net capitalized cost of the Company’s oil and gas properties subject to the amortization (the “carrying value”) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects.
	During 2014 and 2013, the Company recorded a $120 million and $188 million, respectively, non-cash impairment of the carrying value of its oil and gas properties as a result of the ceiling test limitation. Recent steep declines in commodity prices may require further impairment in the future.
	Business Combinations
	The Company accounts for all business combinations using the acquisition method which involves the use of significant judgment. Under the acquisition method of accounting, a business combination is accounted for based on the fair value of the consideration given. The assets and liabilities acquired are measured at fair value and the purchase price is allocated to the assets and liabilities based on these fair values. The excess of the cost of an acquisition, if any, over the fair value of the assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquisition, if any, is recognized immediately in earnings as a gain. Determining the fair values of the assets and liabilities acquired involves the use of judgment since fair values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities and the present value of estimated future cash flows, among others.
	Other Property and Equipment
	Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Field offices and partial ownership of aircraft are depreciated over fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.
	Impairment of Long-Lived Assets Other than Oil and Gas Properties
	Resolute evaluates long-lived assets other than oil and gas properties for impairment when indicators of possible impairment are present. Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the asset’s fair value and an impairment loss is recorded against the long-lived asset. There have been no provisions for impairment recorded for the years ended December 31, 2014, 2013 and 2012.
	Asset Retirement Obligations
	Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted as part of the full cost pool. Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
	The restricted cash of $19.9 million located on the Company’s consolidated balance sheet in non-current other assets at December 31, 2014, is legally restricted for the purpose of settling asset retirement obligations of Aneth Field.
	Derivative Instruments
	Resolute utilizes derivative instruments to manage its exposure to oil and gas price volatility and these instruments may take the form of swaps, puts, calls, collars and other such arrangements. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Resolute has not elected to apply cash flow hedge accounting, and consequently, recognizes gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow hedge accounting. Realized gains and losses on derivative instruments are recognized in the period in which the related contract is settled. Both the realized and mark-to-market gains and losses on derivative instruments are reflected in other income (expense) in the consolidated statements of income. Cash flows from derivatives are reported as cash flows from operating activities.
	Revenue Recognition
	Oil and gas revenue is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and the collectability of the revenue is probable. Oil and gas revenue is recorded using the sales method.
	General and Administrative Expenses
	General and administrative expenses are reported net of amounts capitalized to oil and gas properties and of reimbursements of overhead costs that are billed to working interest owners of the oil and gas properties operated by Resolute.
	Share-Based Compensation Expense
	Share-based compensation expense is measured at the estimated grant date fair value of the awards and is amortized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to share-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur.
	Income Taxes
	Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 740, Accounting for Income Taxes. Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in FASB ASC Topic 740.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3 — Acquisitions and Divestitures
	Permian Property Acquisitions
	On December 21, 2012, the Company purchased properties in Denton Field in the Northwest Shelf in Lea County, New Mexico, and in the Spraberry trend in the Midland Basin portion of the Permian Basin in Howard County, Texas, for a purchase price of approximately $117 million. Additionally, on December 28, 2012, the Company purchased properties in the Wolfberry play in the Midland Basin portion of the Permian Basin in Midland and Ector counties, Texas, for a purchase price of approximately $133 million. Concurrently with the latter transaction, the Company acquired, for additional consideration of $6 million, the option to buy the balance of the working interest in and operatorship of the properties under substantially the same terms as the initial transaction, (the “Option Properties”). On March 22, 2013, the Company exercised the option and acquired the Option Properties for $258 million, net of the option fee after customary purchase price adjustments, which were estimated at closing. Revenue and expenses related to the acquired properties are included in the consolidated statement of operations beginning on the closing date of the respective transaction. The properties acquired under the December and March acquisitions, which the Company refers to as the “Permian Acquisitions,” were accounted for using the acquisition method.
	The purchase price of the Permian Acquisitions was comprised of the following (in thousands):
		2013			2012
	Purchase price	$	258,000		$	250,000
	The Company has completed its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the following table presents the final purchase price allocation of the Permian Acquisitions at December 31, 2013 and 2012, based on the fair values of assets acquired and liabilities assumed (in thousands):
		2013			2012
	Proved oil and gas properties	$	93,000		$	131,000
	Unproved oil and gas properties		167,000			122,000
	Asset retirement obligations assumed		(2,000	)		(3,000	)
	Total purchase price	$	258,000		$	250,000
	Pro Forma Financial Information
	The unaudited pro forma consolidated financial information in the table below summarizes the results of operations of the Company as though the purchase of the Option Properties in March 2013 had occurred on January 1, 2012, and the purchase of the properties in the Permian Basin in December 2012 had occurred on January 1, 2012. The pro forma financial information is presented for informational purposes only and is not indicative of the results of operations that would have been achieved if the Permian Acquisitions had taken place at the beginning of the earliest periods presented or that may result in the future. The pro forma adjustments made utilize certain assumptions that Resolute believes are reasonable based on the available information.
	The unaudited pro forma financial information for the years ended December 31, 2013 and 2012 combine the historical results of the Permian Acquisitions and Resolute (in thousands, except per share amounts):
		2013			2012
	Revenue	$	360,837		$	362,355
	Revenue in excess of operating expenses		215,273			218,815
	Net income (loss)		(111,243	)		30,381
	Basic and diluted net income (loss) per share	$	(1.63	)	$	0.51
	Aneth Field Transactions
	During the second quarter of 2012, Resolute and Navajo Nation Oil and Gas Company (“NNOGC”) entered into two transactions regarding the Aneth Field Properties.
	In the first transaction, effective January 1, 2012, Resolute and NNOGC together, on a 50%/50% basis, acquired from affiliates of Denbury Resources Inc. (“Denbury”) a 13% working interest in the Aneth Unit and an 11% working interest in the Ratherford Unit for a total cash consideration of $75 million. The acquisition from Denbury was accounted for using the acquisition method. After closing adjustments, the $37.7 million net purchase price was allocated to proved oil and gas properties. Revenue and expenses associated with the acquired interests are included in the consolidated statements of income concurrent with the closing of the transaction in April 2012.
	Contemporaneously with this transaction, Resolute and NNOGC also entered into an amendment to their Cooperative Agreement. Among other changes, this amendment allowed NNOGC to exercise options to purchase 10% of the Company’s interest in the Aneth Field Properties, as they existed before giving effect to the Denbury transaction discussed above. These options were exercised for cash consideration of $100 million. Resolute entered into a purchase and sale agreement relating to the exercise of the options which provided that the transaction be closed and paid for in two equal transfers, each for 5% of Resolute’s interest in the properties. The first transfer took place in July 2012 and the second transfer took place in January 2013, each with an effective date of January 1, 2012.
	The Cooperative Agreement amendment also provides for the cancellation of a second set of options held by NNOGC to purchase an additional 10% interest in the Aneth Field Properties and stipulates that NNOGC has one remaining option to purchase an additional 10% of Resolute’s interest in the Aneth Field Properties. The remaining option is exercisable in July 2017 at the then current fair market value of such interest at that time. No gain or loss was recognized upon these sales as it did not represent a significant portion of the Company’s oil and gas properties and did not significantly alter the relationship of capitalized costs and proved reserves.
	The net effect of the acquisition of properties from Denbury and the sale of properties to NNOGC, following full consummation, is that the Company’s working interests in the Aneth Unit and the Ratherford Unit remain essentially unchanged at 62% and 59%, respectively, and its working interest in the McElmo Creek Unit was reduced from 75% to 67.5%. Resolute remains the operator of its Aneth Field Properties.
	Sale of New Home Properties
	On June 27, 2013, the Company entered into a purchase and sale agreement with HRC Energy, LLC, a Colorado limited liability company, and a wholly-owned subsidiary of Halcón Resources Corporation, a Delaware corporation, effective March 1, 2013, to dispose of certain Bakken properties located in Williams County, North Dakota (the “New Home Properties”) and other non-operated Bakken properties for proceeds of $70.1 million. The transaction closed on July 15, 2013 and net proceeds received were recorded as a reduction to the capitalized costs of the Company’s oil and gas properties.

Earnings_per_Share

Earnings per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings per Share	Note 4 — Earnings per Share
	The Company computes basic net income (loss) per share using the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per share is computed using the weighted average number of shares of common stock and, if dilutive, potential shares of common stock outstanding during the period. Potentially dilutive shares consist of the incremental shares issuable under the Company’s 2009 Performance Incentive Plan (the “Incentive Plan”). The treasury stock method is used to measure the dilutive impact of potentially dilutive shares.
	The following table details the potential weighted average dilutive and anti-dilutive securities for the periods presented (in thousands):
		Twelve Months Ended December 31,
		2014			2013			2012
	Potential dilutive restricted stock		2,973			2,529			1,464
	Anti-dilutive securities		27,523			35,569			37,779
	The following table sets forth the 2014, 2013 and 2012 computation of basic and diluted net income (loss) per share of common stock for the periods presented (in thousands, except per share amounts):
		2014			2013			2012
	Net income (loss)	$	(21,850	)	$	(113,806	)	$	17,976
	Basic weighted average common shares outstanding		73,798			68,260			59,424
	Add: dilutive effect of non-vested restricted stock		—			—			28
	Diluted weighted average common shares outstanding		73,798			68,260			59,452
	Basic and diluted net income (loss) per common share	$	(0.30	)	$	(1.67	)	$	0.3
	A summary of the activity associated with warrants during 2014, 2013 and 2012 is as follows (in thousands):
		Warrants
	Balance at December 31, 2012 and 2013		33,041
	Expiration of public warrants		(33,041	)
	Balance at December 31, 2014		—

Long_Term_Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long Term Debt	Note 5 — Long Term Debt
	The Company’s long-term debt consists of the following (in thousands):
		December 31,
		2014			2013
	Revolving credit facility	$	235,000		$	335,000
	Secured term loan facility		150,000			—
	Unamortized discount on secured term loan facility		(10,500	)		—
	8.50% senior notes		400,000			400,000
	Unamortized premium on senior notes		1,461			1,671
	Total long-term debt	$	775,961		$	736,671
	For the years ended December 31, 2014, 2013, and 2012, the Company incurred interest expense on long-term debt of $46.4 million, $45.2 million and $20.2 million, respectively. The Company capitalized $14.9 million, $15.9 million and $4.7 million of interest expense during the years ended December 31, 2014, 2013 and 2012, respectively.
	Revolving Credit Facility
	Resolute’s revolving credit facility is with a syndicate of banks led by Wells Fargo Bank, National Association, as Administrative Agent, and Bank of Montreal, as Syndication Agent (the “Revolving Credit Facility”) with Resolute as the borrower. The Revolving Credit Facility specifies a maximum borrowing base as determined by the lenders. The determination of the borrowing base takes into consideration the estimated value of Resolute’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base is redetermined semi-annually, and the amount available for borrowing could be increased or decreased as a result of such redeterminations. Under certain circumstances, either Resolute or the lenders may request an interim redetermination.
	In March 2013 we entered into the Sixth Amendment, which among other things, extended the maturity date of the Revolving Credit Facility from April 2017 to March 2018. On March 7, 2014, the Company entered into the Ninth Amendment to the amended and restated Revolving Credit Facility which redefined and adjusted the Maximum Leverage Ratio to (a) 4.90:1.00 for the fiscal quarters ending March 31, 2014 and June 30, 2014, (b) 4.75:1.00 for the fiscal quarters ending September 30, 2014 and December 31, 2014, and (c) 4.00:1.00 for all quarters thereafter. The Ninth Amendment also provided that as of the last day of each fiscal quarter in 2104, the ratio of senior secured debt as of such date to Adjusted EDITDA for the four quarter period ending on such date may not exceed 2.75:1.00.
	In December 2014 we entered into the Eleventh Amendment to the amended and restated Revolving Credit Facility agreement. In connection with the Eleventh Amendment, the borrowing base was set at $330 million and certain other amendments were made, including eliminating the total debt-to-EBITDA covenant and conforming the covenant package in the Revolving Credit Facility to that of the Secured Term Loan Facility. The covenants require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5 to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0. Our Revolving Credit Facility and our Secured Term Loan Facility also require us to enter into derivative agreements covering at least 70% of our anticipated production from proved properties on a rolling twenty four month basis, but prohibit us from entering into derivative arrangements for more than (i) 85% of our anticipated production from proved properties in the next two years and (ii) the greater of 75% of our anticipated production from proved properties or 85% of our production from projected proved developed producing reserves using economic parameters specified in our Revolving Credit Facility.
	Each base rate borrowing under the Revolving Credit Facility accrues interest at either (a) the London Interbank Offered Rate, plus a margin which varies from 1.50% to 2.50% or (b) the alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate (ii) the Federal Funds effective Rate plus 0.5% or (iii) an adjusted London Interbank Offered Rate (“LIBOR”) plus a margin which ranges from 0.50% to 1.50%. Each such margin is based on the level of utilization under the borrowing base.
	As of December 31, 2014, outstanding borrowings were $235 million under the borrowing base of $330 million. The borrowing base availability is reduced by $3.1 million in conjunction with letters of credit issued to vendors at December 31, 2014. To the extent that the borrowing base, as adjusted from time to time, exceeds the outstanding balance, no repayments of principal are required prior to maturity. However, should the borrowing base be set at a level below the outstanding balance, we would be required to eliminate that excess over the 120 days following that determination. The Revolving Credit Facility is guaranteed by all of Resolute’s subsidiaries and is collateralized by substantially all of the proved oil and gas assets of Resolute Aneth, LLC, Resolute Wyoming, Inc. and Resolute Natural Resources Southwest, LLC, which are wholly-owned subsidiaries of the Company.
	As of December 31, 2014, the weighted average interest rate on the outstanding balance under the Revolving Credit Facility was 2.17%. The recorded value of the Revolving Credit Facility approximates its fair market value because the interest rate of the Revolving Credit Facility is variable over the term of the loan (Level 2 fair value measurement).
	The Revolving Credit Facility includes customary terms and covenants that place limitations on certain types of activities, the payment of dividends, and require satisfaction of certain financial tests. Resolute was in compliance with all terms and covenants of the Revolving Credit Facility at December 31, 2014.
	Resolute Energy Corporation, the stand-alone parent entity, has insignificant independent assets and no operations. 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.
	Secured Term Loan Agreement
	On December 30, 2014, Resolute and certain of its subsidiaries, as guarantors, entered into a second lien Secured Term Loan Agreement with Bank of Montreal, as administrative agent, and the lenders party thereto, pursuant to which the Company borrowed $150 million. Funding of the Secured Term Loan Facility occurred on December 31, 2014. The Secured Term Loan Facility will mature on the date that is six months after the maturity of the Company’s existing Revolving Credit Facility, but in no event later than November 1, 2019.
	Net proceeds from the Secured Term Loan Facility, approximately $135 million after payment of transaction-related fees, expenses and discounts, were used to repay outstanding amounts under the Revolving Credit Facility.
	Obligations under the Secured Term Loan Facility are guaranteed by certain of the Company’s subsidiaries and secured by second priority liens on substantially all of the assets of the Company and its subsidiaries that serve as collateral under the Revolving Credit Facility.
	Borrowings under the Secured Term Loan Facility will bear interest at adjusted LIBOR plus 10%, with a 1% LIBOR floor. The covenants in the Secured Term Loan Facility require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5 to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0.
	The Company may prepay all or a portion of the Secured Term Loan Facility at any time. The Secured Term Loan Facility is subject to mandatory prepayments of 75% of the net cash proceeds from asset sales, subject to a limited right to reinvest proceeds in oil and gas activities. Prepayments made out of proceeds from asset sales are not subject to prepayment premiums. Mandatory repayments are required of 100% of the net cash proceeds of certain debt or equity issuances. Such prepayments are subject to a premium of between 10% declining to 2% during the first 36 months after closing. To the extent not otherwise achieved, aggregate repayments that substantially pay off principal amounts under the second lien facility shall include an additional payment sufficient to ensure that the lenders achieve a 1.25 to 1.0 minimum multiple of their invested capital.
	The fair value of the Secured Term Loan Facility at December 31, 2014, was estimated to be $139.5 million based on the cash received as of the transaction date (Level 1 fair value measurement).
	Senior Notes
	In April 2012 the Company consummated a private placement of senior notes with a principal amount of $250 million, and in December 2012 placed a follow-on issuance of senior notes with a principal amount of $150 million. The Senior Notes are due May 1, 2020 and bear an annual interest rate of 8.50% with the interest on the Notes payable semiannually in cash on May 1 and November 1 of each year. Resolute used the $250 million of proceeds from the May 2012 issuance to repay outstanding borrowings under the Revolving Credit Facility, with the remainder reserved for general corporate purposes, including capital expenditures. The Company used the $150 million of proceeds from the December 2012 issuance to partially finance the Permian Acquisitions.
	The Senior Notes were issued under an Indenture (the “Indenture”) among the Company, the Company’s existing subsidiaries (the “Guarantors”) and U.S. Bank National Association, as trustee (the “Trustee”) in a private transaction not subject to the registration requirements of the Securities Act of 1933. In March 2013, the Company registered the Senior Notes with the Securities and Exchange Commission by filing an amendment to the registration statement on Form S-4 enabling holders of the Senior Notes to exchange the privately placed Notes for publically registered Notes with substantially identical terms. The Indenture contains affirmative and negative covenants that, among other things, limit the Company’s and the Guarantors’ ability to make investments, incur additional indebtedness or issue preferred stock, create liens, sell assets, enter into agreements that restrict dividends or other payments by restricted subsidiaries, consolidate, merge or transfer all or substantially all of the assets of the Company, engage in transactions with the Company’s affiliates, pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under its Senior Notes as of December 31, 2014.
	The Senior Notes are general unsecured senior obligations of the Company and guaranteed on a senior unsecured basis by the Guarantors. The Senior Notes rank equally in right of payment with all existing and future senior indebtedness of the Company, will be subordinated in right of payment to all existing and future senior secured indebtedness of the Guarantors, will rank senior in right of payment to any future subordinated indebtedness of the Company and will be fully and unconditionally guaranteed by the Guarantors on a senior basis.
	The Senior Notes are redeemable by the Company on or after May 1, 2016 on not less than 30 or more than 60 days’ prior notice, at redemption prices set forth in the Indenture. In addition, at any time prior to May 1, 2015, the Company may use the net proceeds from equity offerings and warrant exercises to redeem up to 35% of the principal amount of Notes issued under the Indenture at a redemption price equal to 108.50% of the principal amount of the Notes redeemed, plus accrued and unpaid interest. The Senior Notes may also be redeemed at any time prior to May 1, 2016 at the option of the Company at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the applicable premium, and accrued and unpaid interest and additional interest, if any, to the applicable redemption date as set forth in the Indenture. If a change of control occurs, each holder of the Notes will have the right to require that the Company purchase all of such holder’s Notes in an amount equal to 101% of the principal of such Notes, plus accrued and unpaid interest, if any, to the date of the purchase.
	The fair value of the Senior Notes at December 31, 2014, was estimated to be $194.0 million based upon data from independent market makers (Level 2 fair value measurement).

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Note 6 — Income Taxes
	The following table summarizes the components of the provision for income taxes (in thousands):
		2014				2013				2012
	Current income tax benefit (expense)	$	—			$	16			$	(16	)
	Deferred income tax benefit (expense)		4,140				64,663				(11,865	)
	Total income tax benefit (expense)	$	4,140			$	64,679			$	(11,881	)
	The provision for income taxes for the years ended December 31, 2014, 2013 and 2012 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. This difference relates primarily to state income taxes and estimated permanent differences as follows (in thousands):
		2014				2013				2012
	Expected statutory income tax benefit (expense)	$	9,097			$	62,470			$	(10,450	)
	State income tax benefit (expense)		480				3,254				(694	)
	Equity compensation		(4,273	)			(2,031	)			(703	)
	Non-deductible executive compensation		(468	)			(54	)			(215	)
	Other		(696	)			1,040				181
	Total income tax benefit (expense)	$	4,140			$	64,679			$	(11,881	)
	The tax effects of temporary differences that give rise to significant portions of the deferred income tax assets and liabilities are presented below (in thousands):
				December 31,
				2014				2013
	Current deferred income tax assets (liabilities):
	Derivative financial instruments			$	(26,919	)		$	3,914
	Asset retirement obligation				121				675
	Equity compensation				2,803				2,924
	Other				772				817
	Total current assets (liabilities)				(23,223	)			8,330
	Long term deferred income tax assets (liabilities):
	Derivative financial instruments				(14,726	)			—
	Net operating loss carryovers				97,022				62,457
	Asset retirement obligation				11,475				11,161
	Startup and organization costs				140				158
	Deferred acquisition costs				45				45
	Percentage depletion				1,341				1,323
	Property and equipment costs				(95,378	)			(110,566	)
	Equity compensation				1,144				1,233
	Other				(194	)			(635	)
	Total long term assets (liabilities)				869				(34,824	)
	Net deferred tax liability			$	(22,354	)		$	(26,494	)
	The Company has U.S. net operating loss carry forwards of $264.8 million at December 31, 2014, which will begin expiring in 2026. A valuation allowance against deferred tax assets at December 31, 2014 is not considered necessary because in the Company’s opinion it is more likely than not that the deferred tax asset will be fully realized.
	The Company previously adopted the accounting for uncertain tax positions per FASB ASC Topic 740, Accounting for Income Taxes. This guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This guidance requires that the Company recognize in the consolidated financial statements, only those tax positions that are “more-likely-than-not” of being sustained, based on the technical merits of the position. This guidance had no effect on the Company’s financial position, cash flows or results of operations for 2014, 2013 or 2012 as the Company had no unrecognized tax benefits. The Company’s policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. The Company has no accrued interest or penalties related to uncertain tax positions as of December 31, 2014, 2013 or 2012.
	The Company is subject to the following material taxing jurisdictions: U.S. federal, Colorado, Texas and Utah. The tax years that remain open to examination by the Internal Revenue Service are the years 2011 through 2014. The tax years that remain open to examination by state taxing authorities are 2010 through 2014.

Stockholders_Equity_and_Equity

Stockholders' Equity and Equity Based Awards	12 Months Ended
	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stockholders' Equity and Equity Based Awards	Note 7 — Stockholders’ Equity and Equity Based Awards
	Preferred Stock
	The Company is authorized to issue up to 1,000,000 shares of preferred stock, par value $0.0001 with such designations, voting and other rights and preferences as may be determined from time to time by the Board of Directors. No shares were issued and outstanding as of December 31, 2014 or December 31, 2013.
	Common Stock
	The authorized common stock of the Company consists of 225,000,000 shares. The holders of the common shares are entitled to one vote for each share of common stock. In addition, the holders of the common stock are entitled to receive dividends when, as and if declared by the Board of Directors. At December 31, 2014 and 2013, the Company had 77,634,737 and 76,228,055 shares of common stock issued and outstanding, respectively.
	During the second quarter 2013, the Company issued 13.3 million shares of common stock in a public offering at $8.00 per share for net proceeds of $101.8 million, after underwriting discounts and commissions. The net proceeds were used to repay outstanding borrowings under the Revolving Credit Facility.
	During 2014 and 2013, no warrants were repurchased. During the second quarter of 2012 the Company repurchased 9,634,821 warrants for aggregate consideration of approximately $10.0 million in a private transaction at an average price of $1.04 per warrant. During 2014, 2013 and 2012, no warrants were exercised. At December 31, 2014, no warrants remain outstanding as all warrants expired on September 25, 2014.
	Share-Based Compensation
	The Company accounts for share-based compensation in accordance with FASB ASC Topic 718, Stock Compensation.
	On July 31, 2009, the Company adopted the Incentive Plan, providing for long-term share-based awards intended as a means for the Company to attract, motivate, retain and reward directors, officers, employees and other eligible persons through the grant of awards and incentives for high levels of individual performance and improved financial performance of the Company. The share-based awards are also intended to further align the interests of award recipients and the Company’s stockholders. The maximum number of shares of common stock that may be issued under the Incentive Plan is 9,157,744.
	Time-Based Awards
	Shares of time-based restricted stock generally vest in three or four year increments at specified dates based on continued employment.
	The compensation expense to be recognized for the time-based awards was measured based on the Company’s closing stock price on the dates of grant, utilizing estimated forfeiture rates between 8% and 10% which are updated periodically based on actual employee turnover. During the year ended December 31, 2014, the Company granted 1,595,535 shares of time-based restricted stock to employees and directors, pursuant to the Incentive plan.
	During 2014, 2013 and 2012, the Company recorded $12.1 million, $11.0 million and $7.2 million of share-based compensation expense related to time-based awards, net of amounts billed to partners, respectively. There was unrecognized compensation expense of approximately $16.7 million at December 31, 2014, which is expected to be recognized over a weighted-average period of 1.7 years. The following table summarizes the changes in non-vested time-based awards for the periods presented:
		2014						2013						2012
					Weighted						Weighted						Weighted
					Average						Average						Average
					Grant Date						Grant Date						Grant Date
		Shares			Fair Value			Shares			Fair Value			Shares			Fair Value
	Non-vested, beginning of period		2,005,721		$	10.62			1,176,890		$	12			952,920		$	14.11
	Granted		1,595,535			8.86			1,570,393			10.31			811,080			10.16
	Vested		(819,615	)		10.87			(559,763	)		12.47			(543,593	)		12.83
	Forfeited		(283,811	)		9.65			(181,799	)		11.15			(43,517	)		13.18
	Non-vested, end of period		2,497,830		$	9.43			2,005,721		$	10.62			1,176,890		$	12
	Performance-Based Awards
	For grants made through year-end 2012, performance-based shares generally vest in equal tranches beginning on December 31 of the year of the grant if there has been a 10% annual appreciation in the trading price of the Company’s common stock, compounded annually, from the twenty trading day average stock price ended on December 31 of the year prior to the grant (which was $14.227 for 2011 grants and $11.639 for 2012 grants). At the end of each year, the twenty trading day average stock price will be measured, and if the 10% threshold is met, the stock subject to the performance criteria will vest. If the 10% threshold is not met, shares that have not vested will be carried forward to the following year subject to a four year maximum vesting period. These awards are referred to as “Stock Appreciation Awards.” At December 31, 2014 and 2013, 156,793 and 390,174 of the Stock Appreciation Awards, respectively, were forfeited by their holders as the four year maximum vesting period for the grants had expired and the 10% threshold had not been met.
	During 2014, 2013 and 2012, the Company recorded share-based compensation expense related to the Stock Appreciation Awards of $0.2 million, $0.8 million and $2.2 million, respectively. There was unrecognized compensation expense for the Stock Appreciation Awards of approximately $0.1 million at December 31, 2014, which is expected to be recognized over a weighted-average period of 1.0 year. The following table summarized changes in non-vested Stock Appreciation Awards for the periods presented:
		2014						2013						2012
					Weighted						Weighted						Weighted
					Average						Average						Average
					Grant Date						Grant Date						Grant Date
		Shares			Fair Value			Shares			Fair Value			Shares			Fair Value
	Non-vested, beginning of period		444,571		$	7.6			895,892		$	8.43			600,310		$	10.71
	Granted		—			—			—		—				316,008			4.02
	Vested		—			—			—		—			—			—
	Forfeited		(21,126	)		7.04			(61,147	)		7.82			(20,426	)		7.56
	Expired		(156,793	)		13.89			(390,174	)		9.38		—			—
	Non-vested, end of period		266,652		$	3.95			444,571		$	7.6			895,892		$	8.43
	In 2014 and 2013, the Compensation Committee awarded 487,819 and 354,517 performance-based restricted shares, respectively, to executive officers of the Company under the Incentive Plan. The restricted stock grants vest only upon achievement of thresholds of cumulative total shareholder return (“TSR”) as compared to a specified peer group (the “Performance-Vested Shares”). A TSR percentile (the “TSR Percentile”) is calculated based on the change in the value of the Company’s common stock between the grant date and the applicable vesting date, including any dividends paid during the period, as compared to the respective TSRs of a specified group of seventeen peer companies. The Performance-Vested Shares vest in three installments to the extent that the applicable TSR Percentile ranking thresholds are met upon the one-, two- and three-year anniversaries of the grant date. Performance-Vested Shares that are eligible to vest on a vesting date, but do not qualify for vesting, become eligible for vesting again on the next vesting date. All Performance-Vested Shares that do not vest as of the final vesting date will be forfeited on such date.
	The Compensation Committee also granted rights to earn additional shares of common stock upon achievement of a higher TSR Percentile (“Outperformance Shares”). The Outperformance Shares are earned in increasing increments based on a TSR Percentile attained over a specified threshold. Outperformance Shares may be earned on any vesting date to the extent that the applicable TSR Percentile ranking thresholds are met in three installments on the one-, two- and three-year anniversaries of the grant date. Outperformance Shares that are earned at a vesting date will be issued to the recipient; however, prior to such issuance, the recipient is not entitled to stockholder rights with respect to Outperformance Shares. Outperformance Shares that are eligible to be earned but remain unearned on a vesting date become eligible to be earned again on the next vesting date. The right to earn any theretofore unearned Outperformance Shares terminates immediately following the final vesting date. The Performance-Vested Shares and the Outperformance Shares are referred to as the “TSR Awards.”
	The compensation expense to be recognized for the TSR Awards and Stock Appreciation Awards was measured based on the estimated fair value at the date of grant using a Monte Carlo simulation model and utilizes estimated forfeiture rates between 4% and 15% which are updated periodically based on actual employee turnover.
	The valuation model for the Performance-Based Awards used the following assumptions:
	Grant Year	Average Expected Volatility			Expected Dividend Yield			Risk-Free Interest Rate
	2012	32.1% - 33.0%				0%		0.56% - 0.85%
	2013		35.00%			0%			0.42%
	2014		39.40%			0%			0.69%
	During 2014 and 2013, the Company recorded share-based compensation expense related to the TSR Awards of $4.0 million and $3.1 million, respectively. There was unrecognized compensation expense for TSR Awards of approximately $4.5 million at December 31, 2014, which is expected to be recognized over a weighted-average period of 1.8 years. The following table summarized changes in non-vested TSR Awards for the periods presented:
					2014						2013
								Weighted						Weighted
								Average						Average
								Grant Date						Grant Date
					Shares			Fair Value			Shares			Fair Value
	Non-vested, beginning of period					340,166		$	15.91			—		$	—
	Granted					487,819			13.32			354,517			15.91
	Vested					(63,387	)		15.91			—			—
	Forfeited					—			—			(14,351	)		15.91
	Non-vested, end of period					764,598		$	14.26			340,166		$	15.91

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Note 8 — Asset Retirement Obligation
	Resolute’s estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised that ranges between 7% and 12%. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells. Asset retirement obligations are valued utilizing Level 3 fair value measurement inputs.
	The following table provides a reconciliation of Resolute’s asset retirement obligations for the periods presented, (in thousands):
		December 31,
		2014			2013
	Asset retirement obligations at beginning of period	$	31,989		$	19,155
	Additional liability incurred / acquired		144			2,165
	Accretion expense		2,576			1,327
	Liabilities settled		(1,282	)		(1,573	)
	Revisions to previous estimates		(2,087	)		10,915
	Asset retirement obligations at end of period		31,340			31,989
	Less: current asset retirement obligations		(327	)		(1,825	)
	Long-term asset retirement obligations	$	31,013		$	30,164

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments	Note 9 — Derivative Instruments
	Resolute enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Resolute has not elected to designate derivative instruments as hedges under the provisions of FASB ASC Topic 815, Derivatives and Hedging. As a result, these derivative instruments are marked to market at the end of each reporting period and changes in the fair value are recorded in the accompanying consolidated statements of operations. Gains and losses on commodity derivative instruments from Resolute’s price risk management activities are recognized in other income (expense). The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as financing activities in the condensed consolidated statement of cash flows.
	The Company utilizes fixed price swaps, basis swaps, option contracts and two- and three-way collars. These instruments generally entitle Resolute (the floating price payer in most cases) to receive settlement from the counterparty (the fixed price payer in most cases) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable to each calculation period is less than the fixed strike price or floor price. The Company would pay the counterparty if the settlement price for the scheduled trading days applicable to each calculation period exceeds the fixed strike price or ceiling price. The amount payable by Resolute, if the floating price is above the fixed or ceiling price, is the product of the notional contract quantity and the excess of the floating price over the fixed or ceiling price per calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional contract quantity and the excess of the fixed or floor price over the floating price per calculation period. A three-way collar consists of a two-way collar contract combined with a put option contract sold by the Company with a strike price below the floor price of the two-way collar. The Company receives price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, the Company receives the cash market price plus the variance between the two put option strike prices. This type of instrument captures more value in a rising commodity price environment, but limits the benefits in a downward commodity price environment. Basis swaps, when used in connection with fixed price swaps, fix the price differential between the NYMEX commodity price and the index price at which the production is sold.
	As of December 31, 2014, the fair value of the Company’s commodity derivatives was a net asset of $112.6 million (Level 2 fair value measurement).
	The following table represents Resolute’s commodity swap contracts as of December 31, 2014:
					Oil (NYMEX WTI)								Gas (NYMEX Henry Hub)
	Remaining Term				Bbl per Day				Weighted Average Swap Price per Bbl				MMBtu per Day				Weighted Average  Swap Price per MMBtu
	Jan – Dec 2015					5,600			$	86.8				12,600			$	3.635
	Jan – Dec 2016					6,500			$	80.42				—			$	—
	The following table represents Resolute’s two-way commodity collar contracts as of December 31, 2014:
							Oil (NYMEX WTI)
	Remaining Term						Bbl per Day				Weighted Average Floor Price per Bbl				Weighted Average Ceiling Price per Bbl
	Jan – Dec 2015							1,000			$	84.17			$	92.1
	The following table represents Resolute’s three-way gas collar contracts as of December 31, 2014:
					Gas (NYMEX Henry Hub)
									Weighted Average Short Put				Weighted Average Floor				Weighted Average Ceiling
	Remaining Term				MMBtu per Day				Price per MMBtu				Price per MMBtu				Price per MMBtu
	Jan – Mar 2015					5,000			$	3.75			$	4.5			$	5.55
	Resolute does not offset the fair value amounts of derivative assets and liabilities with the same counterparty for financial reporting purposes. See Note 10 for the location and fair value amounts of Resolute’s commodity derivative instruments reported in the consolidated balance sheets at December 31, 2014 and 2013.
	The table below summarizes the location and amount of commodity derivative instrument gains and losses reported in the consolidated statements of income (in thousands):
		2014			2013				2012
	Other income (expense):
	Commodity derivative settlements	$	(4,988	)	$	(35,812	)		$	(22,920	)
	Mark-to-market gain		123,129			20,476				28,096
	Commodity derivative instruments gain (loss)	$	118,141		$	(15,336	)		$	5,176
	Credit Risk and Contingent Features in Derivative Instruments
	Resolute is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. All counterparties are lenders under Resolute’s Credit Facility. Accordingly, Resolute is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Credit Facility. Resolute’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. Master Agreement (“ISDA”). Typical terms for each ISDA include credit support requirements, cross default provisions, termination events, and set-off provisions. Resolute has set-off provisions with its lenders that, in the event of counterparty default, allow Resolute to set-off amounts owed under the Credit Facility or other general obligations against amounts owed for derivative contract liabilities.
	The maximum amount of loss in the event of all counterparties defaulting is $112.6 million as of December 31, 2014, due to the set off provisions noted above.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 10 — Fair Value Measurements
	FASB ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The guidance establishes a hierarchy for determining the fair values of assets and liabilities, based on the significance level of the following inputs:
	—	Level 1 – Quoted prices in active markets for identical assets or liabilities.
	—	Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
	—	Level 3 – Significant inputs to the valuation model are unobservable.
	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. Resolute’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. Following is a description of the valuation methodologies used by Resolute as well as the general classification of such instruments pursuant to the hierarchy.
	As of December 31, 2014, Resolute’s commodity derivative instruments were required to be measured at fair value on a recurring basis. Resolute used the income approach in determining the fair value of its derivative instruments, utilizing present value techniques for valuing its swaps and basis swaps and option-pricing models for valuing its options. Inputs to these valuation techniques include published forward index prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. Substantially all of these inputs are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the valuation hierarchy.
	The following is a listing of Resolute’s commodity derivative assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2014 and December 31, 2013 (in thousands):
			Level 2
			31-Dec-14		31-Dec-13
	Assets
	Derivative instruments, current		$	72,753	$	1,378
	Derivative instruments, long term			39,799	—
	Total assets		$	112,552	$	1,378
	Liabilities
	Derivative instruments, current		$	—	$	11,955
	Derivative instruments, long term		—		—
	Total liabilities		$	—	$	11,955

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 11 — Commitments and Contingencies
	CO2 Take-or-Pay Agreements
	Resolute is party to a take-or-pay purchase agreement with Kinder Morgan CO2 Company L.P., under which Resolute has committed to buy specified volumes of CO2. The purchased CO2 is for use in Resolute’s enhanced tertiary recovery projects in Aneth Field. Resolute is obligated to purchase a minimum daily volume of CO2 or pay for any deficiencies at the price in effect when delivery was to have occurred. The ultimate CO2 volumes planned for use on the enhanced recovery projects exceed the minimum daily volumes provided in these take-or-pay purchase agreements. Although the Company may incur deficiency payments from time to time, Resolute expects to avoid any permanent payments for deficiencies over the term of the agreement.
	Future minimum CO2 purchase commitments as of December 31, 2014, under this purchase agreement, based on prices and volumes in effect at December 31, 2014, are as follows (in thousands):
		CO2 Purchase
	Year	Commitments
	2015	$	13,499
	2016		12,408
	2017		561
	Total	$	26,468
	Operating Leases
	For 2014, 2013 and 2012, month-to-month office facilities rental payments charged to expense were approximately $1.6 million, $2.0 million and $1.5 million, respectively. The Company is also party to several field equipment and compressor leases used in the CO2 project as well as various vehicle lease agreements. For 2014, 2013 and 2012, the Company’s net rental expense related to these leases was $2.6 million, $2.9 million and $2.6 million, respectively.
	Future payments for the Company’s office facilities, equipment leases and vehicle leases under these operating lease agreements, as of December 31, 2014, are as follows (in thousands):
	Year	Office Lease Rentals		Field Equipment Rentals		Vehicle Lease Rentals		Total
	2015	$	1,525	$	2,094	$	1,220	$	4,839
	2016		1,764		1,637		677		4,078
	2017		1,700		1,473		358		3,531
	2018 and thereafter		5,950		245		82		6,277
	Total	$	10,939	$	5,449	$	2,337	$	18,725
	Escrow Funding Agreement
	Under the terms of Resolute’s predecessor Company’s purchase of working interests in Greater Aneth from ExxonMobil Corporation (the “ExxonMobil Properties”) in 2006, Resolute and NNOGC were required to fund an escrow account sufficient to complete abandonment, well plugging, site restoration and related obligations arising from ownership of the acquired interests. The contribution net to the Company’s working interest, is included in “other assets: restricted cash” in the consolidated balance sheets at December 31, 2014 and 2013. The Company is required to make additional deposits to the escrow account annually. From 2015 through 2016, Resolute must fund approximately $1.6 million per year. In years after 2016, the Company must fund additional payments averaging approximately $0.9 million per year until 2031. Total contributions from the date of acquisition through 2031 will aggregate $26.0 million. Annual interest earned in the escrow account, if any, becomes part of the balance and reduces the payment amount required for funding the escrow account each year. As of December 31, 2014, the Company has funded the 2014 annual contractual amount of approximately $1.6 million required to meet its future obligation.
	NNOGC Purchase Options
	Resolute’s purchase of the Aneth Field Properties was facilitated by the predecessor Company’s strategic alliance with NNOGC and, through NNOGC, the Navajo Nation. This strategic alliance with NNOGC is embodied in a Cooperative Agreement consummated with NNOGC in 2004 to facilitate the joint acquisition of working interests in Greater Aneth from Chevron Corporation and its affiliates (the “Chevron Properties”). The agreement was amended subsequently to facilitate the joint acquisition of the ExxonMobil Properties and was amended again in conjunction with the sale of 10% of the Company’s interest in Aneth Field to NNOGC during the second quarter of 2012.
	Under the original terms of the Cooperative Agreement, NNOGC was granted three separate but substantially similar purchase options. Each purchase option entitled NNOGC to purchase from Resolute up to 10% of the undivided working interests in the Chevron Properties or the ExxonMobil Properties, as applicable, as to each unit in the Aneth Field Properties. The Cooperative Agreement amendment executed in 2012 provides for the cancellation of the second set of options held by NNOGC to purchase an additional 10% interest in the Aneth Field Properties and stipulates that NNOGC has one remaining option to purchase an additional 10% of the Company’s interest in the Aneth Field Properties (as it stood prior to the current option exercise and excluding the interest acquired from Denbury and certain other minority interests). The remaining option is exercisable in July 2017 at the then current fair market value of such interest. The exercise by NNOGC of its remaining purchase option in full would not give it the right to remove Resolute as operator of any of the Aneth Field Properties.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Supplemental Oil and Gas Information	Note 12 — Supplemental Oil and Gas Information (unaudited)
	Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities
	Costs incurred during 2014, 2013 and 2012 related to oil and gas property acquisition, exploration and development activities, including the fair value of oil and gas properties acquired are summarized as follows (in thousands):
			2014			2013			2012
	Acquisition costs
	Proved		$	—		$	155,958		$	166,951
	Unproved			7,007			121,362			125,059
	Exploration costs			111,769			150,072			120,570
	Development costs*			50,291			97,308			100,579
	Total		$	169,067		$	524,700		$	513,159
	*Includes $16.3 million, $20.0 million and $16.2 million of acquired CO2 during 2014, 2013 and 2012, respectively.
	Capitalized Costs of Oil and Gas Properties
	Net capitalized costs related to Resolute’s oil and gas producing activities at December 31, 2014 and December 31, 2013 were as follows (in thousands):
			2014			2013
	Proved oil and gas properties		$	1,706,847		$	1,544,942
	Unevaluated oil and gas properties, not subject			270,375			274,420
	to amortization
	Accumulated depletion, depreciation and amortization			(738,979	)		(491,279	)
	Oil and gas properties, net		$	1,238,243		$	1,328,083
	Oil and Gas Reserve Quantities
	The reserve data as of December 31, 2014 was prepared by Resolute. Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers, audited all properties. Users of this information should be aware that the process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
	Presented below is a summary of the changes in estimated reserves (in thousands):
												Oil Equivalent
			Oil (Bbl)			Gas (MMcf)			NGL (Bbl)			(Boe)(1)
	Proved reserves as of January 1, 2012			52,841			35,157			6,097			64,798
	Purchase of minerals in place			9,463			10,375			2,182			13,374
	Production			(2,773	)		(3,567	)		(41	)		(3,409	)
	Extensions, discoveries and other additions (2)			4,115			3,400			243			4,924
	Sales of minerals in place			(2,391	)		(735	)		(203	)		(2,717	)
	Revisions of previous estimates			1,302			3,091			(14	)		1,804
	Proved reserves as of December 31, 2012			62,557			47,721			8,264			78,774
	Purchase of minerals in place			4,592			10,821			1,422			7,818
	Production			(3,499	)		(4,565	)		(207	)		(4,467	)
	Extensions, discoveries and other additions (2)			4,038			6,128			746			5,805
	Sales of minerals in place			(5,124	)		(3,379	)		(219	)		(5,906	)
	Revisions of previous estimates (3)			(15,053	)		(14,337	)		(5,189	)		(22,630	)
	Proved reserves as of December 31, 2013			47,511			42,389			4,817			59,394
	Purchase of minerals in place			—			—			—			—
	Production			(3,489	)		(6,942	)		—			(4,647	)
	Extensions, discoveries and other additions (2)			25,756			10,128			1,357			28,800
	Sales of minerals in place			(215	)		(26	)		(5	)		(224	)
	Revisions of previous estimates			(5,848	)		(8,751	)		(1,799	)		(9,105	)
	Proved reserves as of December 31, 2014			63,715			36,798			4,370			74,218
	Proved developed reserves:
	As of December 31, 2014			34,359			25,775			2,791			41,446
	As of December 31, 2013			38,791			29,488			3,136			46,842
	As of December 31, 2012			39,288			25,568			2,668			46,217
	Proved undeveloped reserves:
	As of December 31, 2014			29,356			11,023			1,579			32,772
	As of December 31, 2013			8,720			12,901			1,681			12,552
	As of December 31, 2012			23,268			22,153			5,596			32,557
	1)	In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, our estimated net proved reserves and standardized measure at December 31, 2014 and 2013, utilized prices (subsequently adjusted for quality and basis differentials) of an average NYMEX West Texas Intermediate oil price of $94.99 and $96.94 per Bbl for the Aneth Properties and Plains Marketing, L.P. West Texas Intermediate oil price of $91.48 and $93.42 per Bbl for the Permian and Wyoming Properties, and an average Henry Hub spot marketing gas price of $4.35 and $3.67 per one MMBtu of gas, respectively. At December 31, 2012, we used an average NYMEX West Texas Intermediate oil price of $94.71 per Bbl, and an average Henry Hub spot market gas price of $2.76 per MMBtu.
	2)	Extensions, discoveries and other additions in 2014 are primarily associated with reinstatement of CO2 enhanced recovery projects that were removed for year-end 2013 reporting to comply with the SEC five-year rule pertaining to undeveloped reserves. Approximately 21.1 MMBoe have been reinstated as proved undeveloped all comprised of four named CO2 injection projects identified in the Aneth Field Properties: 8.9 MMBoe for Aneth Unit Phase 4 CO2 injection, 3.0 MMBoe for McElmo Unit DCIIC CO2 injection, 4.9 MMBoe for Ratherford DCIA CO2 injection and 4.3 MMBoe for Ratherford DCIIC CO2 injection. Additionally, the Permian and Powder River Basin properties held active drilling programs in 2014 resulting in 1.7 MMBoe added to proved developed producing from successful drilling of non-proved locations. Furthermore, these successful wells created additional proved undeveloped offset locations carrying 6.0 MMBoe reserves.
	3)	Decreases in proved reserves associated with revisions of previous estimates resulted from management’s decision to allocate more of its 2014 capital expenditures towards exploitation drilling of higher expected rates-of-return horizontal wells in the Permian Basin and less capital towards development projects in Aneth Field. Deferral of these projects to 2015 and beyond decreased proved undeveloped reserves by approximately 25 MMBoe, as these projects were no longer expected to be converted to developed reserves within five years after their initial recognition as proved reserves as required under SEC rules, offset by approximately 3 MMBoe converted to proved developed during 2013. The deferred will be again eligible as proved undeveloped reserves in the future, at such time as management adopts a definitive plan to complete the projects.
	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
	The following summarizes the policies used in the preparation of the accompanying oil and gas reserves disclosures, standardized measures of discounted future net cash flows from proved oil and gas reserves and the reconciliations of standardized measures at December 31, 2014. The information disclosed is an attempt to present the information in a manner comparable with industry peers.
	The information is based on estimates of proved reserves attributable to Resolute’s interest in oil and gas properties as of December 31, 2014. Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
	The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:
	1)	Estimates were made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.
	2)	The estimated future cash flows were compiled by applying average annual prices of oil and gas relating to Resolute’s proved reserves to the year-end quantities of those reserves.
	3)	The future cash flows were reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.
	4)	Future income tax expenses were based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credits and allowances relating to Resolute’s proved oil and gas reserves.
	5)	Future net cash flows were discounted to present value by applying a discount rate of 10%.
	The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of Resolute’s oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932:
		December 31,
		2014			2013			2012
		(in thousands)
Future cash inflows		$	5,858,000		$	4,647,000		$	5,983,000
Future production costs			(2,719,000	)		(2,050,000	)		(2,678,000	)
Future development costs			(1,008,000	)		(547,000	)		(832,000	)
Future income taxes			(412,000	)		(398,000	)		(645,000	)
Future net cash flows			1,719,000			1,652,000			1,828,000
10% annual discount for estimated timing of cash flows			(886,000	)		(759,000	)		(956,000	)
Standardized measure of discounted future net cash flows		$	833,000		$	893,000		$	872,000
The principal sources of change in the standardized measure of discounted future net cash flows are:
		December 31,
		2014			2013			2012
		(in thousands)
Standardized measure, beginning of year		$	893,000		$	872,000		$	816,000
Sales of oil and gas produced, net of production costs			(196,000	)		(206,000	)		(157,000	)
Net changes in prices and production costs			(191,000	)		61,000			(201,000	)
Purchases of minerals in place			—			106,000			205,000
Sales of minerals in place			(6,000	)		(84,000	)		(49,000	)
Previously estimated development costs incurred during			49,000			89,000			102,000
the year
Extensions, discoveries and improved recovery			207,000			111,000			105,000
Changes in estimated future development costs			(13,000	)		(64,000	)		(102,000	)
Revisions of previous quantity estimates			(16,000	)		(203,000	)		39,000
Accretion of discount			89,000			79,000			77,000
Net change in income taxes			44,000			67,000			72,000
Changes in timing and other			(27,000	)		65,000			(35,000	)
Standardized measure, end of year		$	833,000		$	893,000		$	872,000

Quarterly_Financial_Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	Note 13 — Quarterly Financial Data (unaudited)
	The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2014 and 2013 (in thousands except per share data):
		Three Months Ended
		March 31,			June 30,			September 30,			December 31,
		2014			2014			2014			2014
	Year Ended December 31, 2014:
	Revenue	$	90,878		$	88,459		$	84,102		$	65,932
	Operating expenses		(79,803	)		(81,527	)		(81,384	)		(199,331	)
	Income (loss) from operations		11,075			6,932			2,718			(133,399	)
	Net income (loss)		(3,548	)		(16,120	)		14,966			(17,148	)
	Earnings (loss) per common share:
	Basic	$	(0.05	)	$	(0.22	)	$	0.2		$	(0.23	)
	Diluted	$	(0.05	)	$	(0.22	)	$	0.2		$	(0.23	)
	Weighted average common shares outstanding:
	Basic		73,540			73,843			73,886			73,917
	Diluted		73,540			73,843			74,050			73,917
		Three Months Ended
		March 31,			June 30,			September 30,			December 31,
		2013			2013			2013			2013
	Year Ended December 31, 2013:
	Revenue	$	78,897		$	89,116		$	89,085		$	92,681
	Operating expenses		(68,885	)		(74,389	)		(70,055	)		(270,318	)
	Income from operations		10,012			14,727			19,030			(177,637	)
	Net income (loss)		(3,049	)		9,023			(2,674	)		(117,106	)
	Earnings (loss) per common share:
	Basic	$	(0.05	)	$	0.14		$	(0.04	)	$	(1.60	)
	Diluted	$	(0.05	)	$	0.14		$	(0.04	)	$	(1.60	)
	Weighted average common shares outstanding:
	Basic		59,802			66,782			73,100			73,123
	Diluted		59,802			66,782			73,100			73,123

Basis_of_Presentation_and_Summ1

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation
	The consolidated financial statements include Resolute and its subsidiaries, and have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). All significant intercompany transactions have been eliminated upon consolidation.
	In connection with the preparation of the consolidated financial statements, Resolute evaluated subsequent events that occurred after the balance sheet date, through the date of filing.
Assumptions, Judgments and Estimates	Assumptions, Judgments and Estimates
	The preparation of the consolidated financial statements in conformity with GAAP requires management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events. Accordingly, actual results could differ from amounts previously established.
	Significant estimates with regard to the consolidated financial statements include proved oil and gas reserve volumes and the related present value of estimated future net cash flows used in the ceiling test applied to capitalized oil and gas properties; asset retirement obligations; valuation of derivative assets and liabilities; the estimated fair value and allocation of the purchase price related to business combinations; share-based compensation expense; depletion depreciation, and amortization; accrued liabilities; revenue and related receivables and income taxes.
Fair Value of Financial Instruments	Fair Value of Financial Instruments
	The carrying amount of the majority of Resolute’s financial instruments, namely cash and cash equivalents, accounts receivable and accounts payable, approximate their fair value because of the short-term nature of these instruments. The revolving credit facility (see Note 5) has a recorded value that approximates its fair market value while the fair value of the $400 million in principal senior notes due May 1, 2020 (the “Senior Notes” or the “Notes”) and the $150 million in the second lien secured term loan due March 2018 (the “Secured Term Loan Facility”) are based on data from independent market makers or price received at measurement date. The fair value of derivative instruments (see Note 10) is estimated based on market conditions in effect at the end of each reporting period.
Industry Segment and Geographic Information	Industry Segment and Geographic Information
	Resolute conducts oil, gas and natural gas liquids (“NGL”) exploration and production operations in one segment. All of Resolute’s operations and assets are located in the United States, and all of its revenue is attributable to domestic customers. Resolute considers gathering, processing and marketing functions as supportive of its oil and gas producing activities, and accordingly, they are not reported as separate segments.
Cash and Cash Equivalents	Cash and Cash Equivalents
	Resolute considers all highly liquid investments with original maturities of three months or less at the date of purchase to be cash equivalents. Resolute periodically maintains cash and cash equivalents in bank deposit accounts and money market funds which may be in excess of federally insured amounts. Resolute has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Accounts Receivable	Accounts Receivable
	The Company’s accounts receivable consist of the following for the periods indicated (in thousands):
		December 31,
		2014		2013
	Trade receivables	$	51,166	$	92,959
	Derivative receivables		6,638		866
	Other receivables		105		533
	Total accounts receivable	$	57,909	$	94,358
	The Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are due within fifteen days and are collected in less than two months, and the Company has had minimal bad debts.
	The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. As of December 31, 2014 and 2013, the Company had no allowance for doubtful accounts recorded.
Deferred Financing Costs	Deferred Financing Costs
	Deferred financing costs are amortized over the estimated life of the related obligation. The Company incurred $4.8 million in deferred financing costs in 2014, $1.9 million in 2013 and $12.3 million in 2012, and amortized $2.5 million, $2.7 million and $1.7 million to interest expense during 2014, 2013 and 2012, respectively.
Capitalized Interest	Capitalized Interest
	Interest is capitalized when associated with significant investments in unproved properties and major development projects that are excluded from current depletion, depreciation and amortization calculations and on which exploration or development activities are in progress. Capitalized interest is calculated by multiplying the Company’s weighted-average interest rate on debt by the amount of qualified costs. Costs excluded from the depletion, depreciation and amortization calculations are classified as unproved properties along with any associated capitalized interest. Capitalized interest totaled $14.9 million, $15.9 million and $4.7 million during 2014, 2013 and 2012, respectively.
Concentration of Credit Risk	Concentration of Credit Risk
	Financial instruments that potentially subject Resolute to concentrations of credit risk consist primarily of trade, production and derivative settlement receivables. Resolute derived approximately 62% and 14% of its total 2014 revenue from Western Refining, Inc. (“Western”) and Plains Marketing LP, respectively; 61% and 15% of its total 2013 revenue from Western and Plains Marketing LP, respectively and 78% of its total 2012 revenue from Western. If Resolute was compelled to sell its oil to an alternative market, costs associated with the transportation of its production may increase, and such increase could materially and negatively affect its operations. The concentration of credit risk in the oil and gas industry affects the overall exposure to credit risk because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements where appropriate. Commodity derivative contracts expose Resolute to the credit risk of non-performance by the counterparty to the contracts. This exposure is diversified among major investment grade financial institutions, all of which participate in Resolute’s Revolving Credit Facility (see Note 5).
Oil and Gas Properties	Oil and Gas Properties
	The Company uses the full cost method of accounting for oil and gas producing activities. All costs incurred in the acquisition, exploration and development of properties, including costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds, delay lease rentals and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities, improved recovery systems and a portion of general and administrative and operating expenses are capitalized on a country wide basis (the “Cost Center”).
	Resolute conducts tertiary recovery projects on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods. Under the full cost method, all development costs are capitalized at the time incurred. Development costs include charges associated with access to and preparation of well locations, drilling and equipping development wells, test wells, and service wells including injection wells, and acquiring, constructing, and installing production facilities and providing for improved recovery systems. Improved recovery systems include all related facility development costs and the cost of the acquisition of tertiary injectants, primarily purchased carbon dioxide (“CO2”). The development costs related to CO2 purchases are incurred solely for the purpose of gaining access to incremental reserves not otherwise recoverable. The accumulation of injected CO2, in combination with additional purchased and recycled CO2, provides future economic value over the life of the project.
	In contrast, other costs related to the daily operation of the improved recovery systems are considered production costs and are expensed as incurred. These costs include, but are not limited to, compression, electricity, separation, re-injection of recovered CO2 and water and reservoir pressure maintenance.
	Capitalized general and administrative and operating costs include salaries, employee benefits, costs of consulting services and other specifically identifiable capital costs and do not include costs related to production operations, general corporate overhead or similar activities. Resolute capitalized general and administrative and operating costs related to its acquisition, exploration and development activities of $9.8 million during 2014, $8.4 million during 2013 and $6.0 million during 2012.
	Investments in unproved properties are not depleted, pending determination of the existence of proved reserves. The Company’s investments in unproved properties are related to exploration plays in the Permian Basin in Texas and southeast New Mexico. The Company expects to evaluate these locations for the existence of proved reserves in the next 1 to 3 years, although volatility in commodity prices may impact the timing of the evaluation. Unproved properties are assessed at least annually to determine whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized.
	No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of the Company’s oil and gas properties and the gain or loss significantly alters the relationship between the capitalized costs and proved reserves of the cost center.
	Depletion of oil and gas properties is computed on the unit-of-production method based on proved reserves. Depletable costs include estimates of asset retirement obligations and future development costs of proved reserves, including, but not limited to, costs to drill and equip development wells, construct and install production and processing facilities, and improved recovery systems, including the cost of required future CO2 purchases.
	Pursuant to full cost accounting rules, accounting rules require Resolute to perform a quarterly “ceiling test” calculation to test its oil and gas properties for possible impairment. The primary components impacting the calculation are commodity prices, reserve quantities added and produced, overall exploration and development costs and depletion expense. If the net capitalized cost of the Company’s oil and gas properties subject to the amortization (the “carrying value”) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects.
	During 2014 and 2013, the Company recorded a $120 million and $188 million, respectively, non-cash impairment of the carrying value of its oil and gas properties as a result of the ceiling test limitation. Recent steep declines in commodity prices may require further impairment in the future.
Business Combinations	Business Combinations
	The Company accounts for all business combinations using the acquisition method which involves the use of significant judgment. Under the acquisition method of accounting, a business combination is accounted for based on the fair value of the consideration given. The assets and liabilities acquired are measured at fair value and the purchase price is allocated to the assets and liabilities based on these fair values. The excess of the cost of an acquisition, if any, over the fair value of the assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquisition, if any, is recognized immediately in earnings as a gain. Determining the fair values of the assets and liabilities acquired involves the use of judgment since fair values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities and the present value of estimated future cash flows, among others.
Other Property and Equipment	Other Property and Equipment
	Other property and equipment are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the assets. Office furniture, automobiles, and computer hardware and software are depreciated over three to five years. Field offices and partial ownership of aircraft are depreciated over fifteen to twenty years. Leasehold improvements are depreciated, using the straight line method, over the shorter of the lease term or the useful life of the asset. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation and amortization are removed from the accounts.
Impairment of Long-Lived Assets Other than Oil and Gas Properties	Impairment of Long-Lived Assets Other than Oil and Gas Properties
	Resolute evaluates long-lived assets other than oil and gas properties for impairment when indicators of possible impairment are present. Resolute performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the asset’s fair value and an impairment loss is recorded against the long-lived asset. There have been no provisions for impairment recorded for the years ended December 31, 2014, 2013 and 2012.
Asset Retirement Obligations	Asset Retirement Obligations
	Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted as part of the full cost pool. Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
	The restricted cash of $19.9 million located on the Company’s consolidated balance sheet in non-current other assets at December 31, 2014, is legally restricted for the purpose of settling asset retirement obligations of Aneth Field.
Derivative Instruments	Derivative Instruments
	Resolute utilizes derivative instruments to manage its exposure to oil and gas price volatility and these instruments may take the form of swaps, puts, calls, collars and other such arrangements. Derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. Resolute has not elected to apply cash flow hedge accounting, and consequently, recognizes gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow hedge accounting. Realized gains and losses on derivative instruments are recognized in the period in which the related contract is settled. Both the realized and mark-to-market gains and losses on derivative instruments are reflected in other income (expense) in the consolidated statements of income. Cash flows from derivatives are reported as cash flows from operating activities.
Revenue Recognition	Revenue Recognition
	Oil and gas revenue is recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and the collectability of the revenue is probable. Oil and gas revenue is recorded using the sales method.
General and Administrative Expenses	General and Administrative Expenses
	General and administrative expenses are reported net of amounts capitalized to oil and gas properties and of reimbursements of overhead costs that are billed to working interest owners of the oil and gas properties operated by Resolute.
Share-Based Compensation Expense	Share-Based Compensation Expense
	Share-based compensation expense is measured at the estimated grant date fair value of the awards and is amortized over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to share-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur.
Income Taxes	Income Taxes
	Income taxes and uncertain tax positions are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 740, Accounting for Income Taxes. Deferred income taxes are provided for the differences between the bases of assets and liabilities for financial reporting and income tax purposes. A valuation allowance is established when necessary to reduce deferred tax assets to the amount expected to be realized. Tax positions meeting the more-likely-than-not recognition threshold are measured pursuant to the guidance set forth in FASB ASC Topic 740.
Computation Of Earnings Per Share	The Company computes basic net income (loss) per share using the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per share is computed using the weighted average number of shares of common stock and, if dilutive, potential shares of common stock outstanding during the period. Potentially dilutive shares consist of the incremental shares issuable under the Company’s 2009 Performance Incentive Plan (the “Incentive Plan”). The treasury stock method is used to measure the dilutive impact of potentially dilutive shares.

Basis_of_Presentation_and_Summ2

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Accounts Receivable	The Company’s accounts receivable consist of the following for the periods indicated (in thousands):
		December 31,
		2014		2013
	Trade receivables	$	51,166	$	92,959
	Derivative receivables		6,638		866
	Other receivables		105		533
	Total accounts receivable	$	57,909	$	94,358

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Purchase Price of New Permian Acquisitions	The purchase price of the Permian Acquisitions was comprised of the following (in thousands):
		2013			2012
	Purchase price	$	258,000		$	250,000
Final Purchase Price Allocation of New Permian Properties	The Company has completed its assessment of the fair values of the assets acquired and liabilities assumed. Accordingly, the following table presents the final purchase price allocation of the Permian Acquisitions at December 31, 2013 and 2012, based on the fair values of assets acquired and liabilities assumed (in thousands):
		2013			2012
	Proved oil and gas properties	$	93,000		$	131,000
	Unproved oil and gas properties		167,000			122,000
	Asset retirement obligations assumed		(2,000	)		(3,000	)
	Total purchase price	$	258,000		$	250,000
Unaudited Pro Forma Financial Information	The unaudited pro forma financial information for the years ended December 31, 2013 and 2012 combine the historical results of the Permian Acquisitions and Resolute (in thousands, except per share amounts):
		2013			2012
	Revenue	$	360,837		$	362,355
	Revenue in excess of operating expenses		215,273			218,815
	Net income (loss)		(111,243	)		30,381
	Basic and diluted net income (loss) per share	$	(1.63	)	$	0.51

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Weighted Average Dilutive and Anti-Dilutive Securities	The following table details the potential weighted average dilutive and anti-dilutive securities for the periods presented (in thousands):
		Twelve Months Ended December 31,
		2014			2013			2012
	Potential dilutive restricted stock		2,973			2,529			1,464
	Anti-dilutive securities		27,523			35,569			37,779
Computation of Basic and Diluted Net Income (Loss) per Share of Common Stock	The following table sets forth the 2014, 2013 and 2012 computation of basic and diluted net income (loss) per share of common stock for the periods presented (in thousands, except per share amounts):
		2014			2013			2012
	Net income (loss)	$	(21,850	)	$	(113,806	)	$	17,976
	Basic weighted average common shares outstanding		73,798			68,260			59,424
	Add: dilutive effect of non-vested restricted stock		—			—			28
	Diluted weighted average common shares outstanding		73,798			68,260			59,452
	Basic and diluted net income (loss) per common share	$	(0.30	)	$	(1.67	)	$	0.3
Activity Associated with Warrants	A summary of the activity associated with warrants during 2014, 2013 and 2012 is as follows (in thousands):
		Warrants
	Balance at December 31, 2012 and 2013		33,041
	Expiration of public warrants		(33,041	)
	Balance at December 31, 2014		—

Long_Term_Debt_Tables

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-term Debt	The Company’s long-term debt consists of the following (in thousands):
		December 31,
		2014			2013
	Revolving credit facility	$	235,000		$	335,000
	Secured term loan facility		150,000			—
	Unamortized discount on secured term loan facility		(10,500	)		—
	8.50% senior notes		400,000			400,000
	Unamortized premium on senior notes		1,461			1,671
	Total long-term debt	$	775,961		$	736,671

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Components of Provision for Income Taxes	The following table summarizes the components of the provision for income taxes (in thousands):
		2014				2013				2012
	Current income tax benefit (expense)	$	—			$	16			$	(16	)
	Deferred income tax benefit (expense)		4,140				64,663				(11,865	)
	Total income tax benefit (expense)	$	4,140			$	64,679			$	(11,881	)
Reconciliation of Provision for Income Taxes to Amount Provided by Applying Statutory United States Federal Income Tax Rate to Income Before Income Taxes	The provision for income taxes for the years ended December 31, 2014, 2013 and 2012 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to income before income taxes. This difference relates primarily to state income taxes and estimated permanent differences as follows (in thousands):
		2014				2013				2012
	Expected statutory income tax benefit (expense)	$	9,097			$	62,470			$	(10,450	)
	State income tax benefit (expense)		480				3,254				(694	)
	Equity compensation		(4,273	)			(2,031	)			(703	)
	Non-deductible executive compensation		(468	)			(54	)			(215	)
	Other		(696	)			1,040				181
	Total income tax benefit (expense)	$	4,140			$	64,679			$	(11,881	)
Tax Effects of Temporary Differences that Give Rise to Significant Portions of Deferred Income Tax Assets and Liabilities	The tax effects of temporary differences that give rise to significant portions of the deferred income tax assets and liabilities are presented below (in thousands):
				December 31,
				2014				2013
	Current deferred income tax assets (liabilities):
	Derivative financial instruments			$	(26,919	)		$	3,914
	Asset retirement obligation				121				675
	Equity compensation				2,803				2,924
	Other				772				817
	Total current assets (liabilities)				(23,223	)			8,330
	Long term deferred income tax assets (liabilities):
	Derivative financial instruments				(14,726	)			—
	Net operating loss carryovers				97,022				62,457
	Asset retirement obligation				11,475				11,161
	Startup and organization costs				140				158
	Deferred acquisition costs				45				45
	Percentage depletion				1,341				1,323
	Property and equipment costs				(95,378	)			(110,566	)
	Equity compensation				1,144				1,233
	Other				(194	)			(635	)
	Total long term assets (liabilities)				869				(34,824	)
	Net deferred tax liability			$	(22,354	)		$	(26,494	)

Stockholders_Equity_and_Equity1

Stockholders' Equity and Equity Based Awards (Tables)	12 Months Ended
	Dec. 31, 2014
Valuation Model for Performance-Based Awards	The valuation model for the Performance-Based Awards used the following assumptions:
	Grant Year	Average Expected Volatility			Expected Dividend Yield			Risk-Free Interest Rate
	2012	32.1% - 33.0%				0%		0.56% - 0.85%
	2013		35.00%			0%			0.42%
	2014		39.40%			0%			0.69%
Time Based Restricted Stock Awards
Changes in Non-Vested Awards	The following table summarizes the changes in non-vested time-based awards for the periods presented:
		2014						2013						2012
					Weighted						Weighted						Weighted
					Average						Average						Average
					Grant Date						Grant Date						Grant Date
		Shares			Fair Value			Shares			Fair Value			Shares			Fair Value
	Non-vested, beginning of period		2,005,721		$	10.62			1,176,890		$	12			952,920		$	14.11
	Granted		1,595,535			8.86			1,570,393			10.31			811,080			10.16
	Vested		(819,615	)		10.87			(559,763	)		12.47			(543,593	)		12.83
	Forfeited		(283,811	)		9.65			(181,799	)		11.15			(43,517	)		13.18
	Non-vested, end of period		2,497,830		$	9.43			2,005,721		$	10.62			1,176,890		$	12
Stock Appreciation Awards
Changes in Non-Vested Awards		2014						2013						2012
					Weighted						Weighted						Weighted
					Average						Average						Average
					Grant Date						Grant Date						Grant Date
		Shares			Fair Value			Shares			Fair Value			Shares			Fair Value
	Non-vested, beginning of period		444,571		$	7.6			895,892		$	8.43			600,310		$	10.71
	Granted		—			—			—		—				316,008			4.02
	Vested		—			—			—		—			—			—
	Forfeited		(21,126	)		7.04			(61,147	)		7.82			(20,426	)		7.56
	Expired		(156,793	)		13.89			(390,174	)		9.38		—			—
	Non-vested, end of period		266,652		$	3.95			444,571		$	7.6			895,892		$	8.43
	The following table summarized changes in non-vested Stock Appreciation Awards for the periods presented:
Performance-based restricted shares
Changes in Non-Vested Awards
					2014						2013
								Weighted						Weighted
								Average						Average
								Grant Date						Grant Date
					Shares			Fair Value			Shares			Fair Value
	Non-vested, beginning of period					340,166		$	15.91			—		$	—
	Granted					487,819			13.32			354,517			15.91
	Vested					(63,387	)		15.91			—			—
	Forfeited					—			—			(14,351	)		15.91
	Non-vested, end of period					764,598		$	14.26			340,166		$	15.91

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of Asset Retirement Obligations	The following table provides a reconciliation of Resolute’s asset retirement obligations for the periods presented, (in thousands):
		December 31,
		2014			2013
	Asset retirement obligations at beginning of period	$	31,989		$	19,155
	Additional liability incurred / acquired		144			2,165
	Accretion expense		2,576			1,327
	Liabilities settled		(1,282	)		(1,573	)
	Revisions to previous estimates		(2,087	)		10,915
	Asset retirement obligations at end of period		31,340			31,989
	Less: current asset retirement obligations		(327	)		(1,825	)
	Long-term asset retirement obligations	$	31,013		$	30,164

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Amount of Commodity Derivative Instrument Gains (Losses)	The table below summarizes the location and amount of commodity derivative instrument gains and losses reported in the consolidated statements of income (in thousands):
		2014			2013				2012
	Other income (expense):
	Commodity derivative settlements	$	(4,988	)	$	(35,812	)		$	(22,920	)
	Mark-to-market gain		123,129			20,476				28,096
	Commodity derivative instruments gain (loss)	$	118,141		$	(15,336	)		$	5,176
Two-Way Commodity Collar
Commodity Contracts and Swaps	The following table represents Resolute’s two-way commodity collar contracts as of December 31, 2014:
							Oil (NYMEX WTI)
	Remaining Term						Bbl per Day				Weighted Average Floor Price per Bbl				Weighted Average Ceiling Price per Bbl
	Jan – Dec 2015							1,000			$	84.17			$	92.1
Three-Way Gas Collar
Commodity Contracts and Swaps	The following table represents Resolute’s three-way gas collar contracts as of December 31, 2014:
					Gas (NYMEX Henry Hub)
									Weighted Average Short Put				Weighted Average Floor				Weighted Average Ceiling
	Remaining Term				MMBtu per Day				Price per MMBtu				Price per MMBtu				Price per MMBtu
	Jan – Mar 2015					5,000			$	3.75			$	4.5			$	5.55
Commodity Swap Contracts
Commodity Contracts and Swaps	The following table represents Resolute’s commodity swap contracts as of December 31, 2014:
					Oil (NYMEX WTI)								Gas (NYMEX Henry Hub)
	Remaining Term				Bbl per Day				Weighted Average Swap Price per Bbl				MMBtu per Day				Weighted Average  Swap Price per MMBtu
	Jan – Dec 2015					5,600			$	86.8				12,600			$	3.635
	Jan – Dec 2016					6,500			$	80.42				—			$	—

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Assets and Liabilities Required to be Measured at Fair Value on Recurring Basis	The following is a listing of Resolute’s commodity derivative assets and liabilities required to be measured at fair value on a recurring basis and where they are classified within the hierarchy as of December 31, 2014 and December 31, 2013 (in thousands):
		Level 2
		31-Dec-14		31-Dec-13
	Assets
	Derivative instruments, current	$	72,753	$	1,378
	Derivative instruments, long term		39,799	—
	Total assets	$	112,552	$	1,378
	Liabilities
	Derivative instruments, current	$	—	$	11,955
	Derivative instruments, long term	—		—
	Total liabilities	$	—	$	11,955

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Future minimum CO2 purchase commitments	Future minimum CO2 purchase commitments as of December 31, 2014, under this purchase agreement, based on prices and volumes in effect at December 31, 2014, are as follows (in thousands):
		CO2 Purchase
	Year	Commitments
	2015	$	13,499
	2016		12,408
	2017		561
	Total	$	26,468
Schedule of Future Payment Operating Leases Agreements	Future payments for the Company’s office facilities, equipment leases and vehicle leases under these operating lease agreements, as of December 31, 2014, are as follows (in thousands):
	Year	Office Lease Rentals		Field Equipment Rentals		Vehicle Lease Rentals		Total
	2015	$	1,525	$	2,094	$	1,220	$	4,839
	2016		1,764		1,637		677		4,078
	2017		1,700		1,473		358		3,531
	2018 and thereafter		5,950		245		82		6,277
	Total	$	10,939	$	5,449	$	2,337	$	18,725

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities	Costs incurred during 2014, 2013 and 2012 related to oil and gas property acquisition, exploration and development activities, including the fair value of oil and gas properties acquired are summarized as follows (in thousands):
			2014			2013			2012
	Acquisition costs
	Proved		$	—		$	155,958		$	166,951
	Unproved			7,007			121,362			125,059
	Exploration costs			111,769			150,072			120,570
	Development costs*			50,291			97,308			100,579
	Total		$	169,067		$	524,700		$	513,159
	*Includes $16.3 million, $20.0 million and $16.2 million of acquired CO2 during 2014, 2013 and 2012, respectively.
Net Capitalized Costs Related to Resolute's Oil and Gas Producing Activities	Net capitalized costs related to Resolute’s oil and gas producing activities at December 31, 2014 and December 31, 2013 were as follows (in thousands):
			2014			2013
	Proved oil and gas properties		$	1,706,847		$	1,544,942
	Unevaluated oil and gas properties, not subject			270,375			274,420
	to amortization
	Accumulated depletion, depreciation and amortization			(738,979	)		(491,279	)
	Oil and gas properties, net		$	1,238,243		$	1,328,083
Changes in Estimated Reserves	Presented below is a summary of the changes in estimated reserves (in thousands):
												Oil Equivalent
			Oil (Bbl)			Gas (MMcf)			NGL (Bbl)			(Boe)(1)
	Proved reserves as of January 1, 2012			52,841			35,157			6,097			64,798
	Purchase of minerals in place			9,463			10,375			2,182			13,374
	Production			(2,773	)		(3,567	)		(41	)		(3,409	)
	Extensions, discoveries and other additions (2)			4,115			3,400			243			4,924
	Sales of minerals in place			(2,391	)		(735	)		(203	)		(2,717	)
	Revisions of previous estimates			1,302			3,091			(14	)		1,804
	Proved reserves as of December 31, 2012			62,557			47,721			8,264			78,774
	Purchase of minerals in place			4,592			10,821			1,422			7,818
	Production			(3,499	)		(4,565	)		(207	)		(4,467	)
	Extensions, discoveries and other additions (2)			4,038			6,128			746			5,805
	Sales of minerals in place			(5,124	)		(3,379	)		(219	)		(5,906	)
	Revisions of previous estimates (3)			(15,053	)		(14,337	)		(5,189	)		(22,630	)
	Proved reserves as of December 31, 2013			47,511			42,389			4,817			59,394
	Purchase of minerals in place			—			—			—			—
	Production			(3,489	)		(6,942	)		—			(4,647	)
	Extensions, discoveries and other additions (2)			25,756			10,128			1,357			28,800
	Sales of minerals in place			(215	)		(26	)		(5	)		(224	)
	Revisions of previous estimates			(5,848	)		(8,751	)		(1,799	)		(9,105	)
	Proved reserves as of December 31, 2014			63,715			36,798			4,370			74,218
	Proved developed reserves:
	As of December 31, 2014			34,359			25,775			2,791			41,446
	As of December 31, 2013			38,791			29,488			3,136			46,842
	As of December 31, 2012			39,288			25,568			2,668			46,217
	Proved undeveloped reserves:
	As of December 31, 2014			29,356			11,023			1,579			32,772
	As of December 31, 2013			8,720			12,901			1,681			12,552
	As of December 31, 2012			23,268			22,153			5,596			32,557
	1)	In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, our estimated net proved reserves and standardized measure at December 31, 2014 and 2013, utilized prices (subsequently adjusted for quality and basis differentials) of an average NYMEX West Texas Intermediate oil price of $94.99 and $96.94 per Bbl for the Aneth Properties and Plains Marketing, L.P. West Texas Intermediate oil price of $91.48 and $93.42 per Bbl for the Permian and Wyoming Properties, and an average Henry Hub spot marketing gas price of $4.35 and $3.67 per one MMBtu of gas, respectively. At December 31, 2012, we used an average NYMEX West Texas Intermediate oil price of $94.71 per Bbl, and an average Henry Hub spot market gas price of $2.76 per MMBtu.
	2)	Extensions, discoveries and other additions in 2014 are primarily associated with reinstatement of CO2 enhanced recovery projects that were removed for year-end 2013 reporting to comply with the SEC five-year rule pertaining to undeveloped reserves. Approximately 21.1 MMBoe have been reinstated as proved undeveloped all comprised of four named CO2 injection projects identified in the Aneth Field Properties: 8.9 MMBoe for Aneth Unit Phase 4 CO2 injection, 3.0 MMBoe for McElmo Unit DCIIC CO2 injection, 4.9 MMBoe for Ratherford DCIA CO2 injection and 4.3 MMBoe for Ratherford DCIIC CO2 injection. Additionally, the Permian and Powder River Basin properties held active drilling programs in 2014 resulting in 1.7 MMBoe added to proved developed producing from successful drilling of non-proved locations. Furthermore, these successful wells created additional proved undeveloped offset locations carrying 6.0 MMBoe reserves.
	3)	Decreases in proved reserves associated with revisions of previous estimates resulted from management’s decision to allocate more of its 2014 capital expenditures towards exploitation drilling of higher expected rates-of-return horizontal wells in the Permian Basin and less capital towards development projects in Aneth Field. Deferral of these projects to 2015 and beyond decreased proved undeveloped reserves by approximately 25 MMBoe, as these projects were no longer expected to be converted to developed reserves within five years after their initial recognition as proved reserves as required under SEC rules, offset by approximately 3 MMBoe converted to proved developed during 2013. The deferred will be again eligible as proved undeveloped reserves in the future, at such time as management adopts a definitive plan to complete the projects.
Future Net Cash Flows Relating to Proved Oil and Gas Reserves	The following summary sets forth Resolute’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by FASB ASC Topic 932:
			December 31,
			2014			2013			2012
			(in thousands)
	Future cash inflows		$	5,858,000		$	4,647,000		$	5,983,000
	Future production costs			(2,719,000	)		(2,050,000	)		(2,678,000	)
	Future development costs			(1,008,000	)		(547,000	)		(832,000	)
	Future income taxes			(412,000	)		(398,000	)		(645,000	)
	Future net cash flows			1,719,000			1,652,000			1,828,000
	10% annual discount for estimated timing of cash flows			(886,000	)		(759,000	)		(956,000	)
	Standardized measure of discounted future net cash flows		$	833,000		$	893,000		$	872,000
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows	The principal sources of change in the standardized measure of discounted future net cash flows are:
			December 31,
			2014			2013			2012
			(in thousands)
	Standardized measure, beginning of year		$	893,000		$	872,000		$	816,000
	Sales of oil and gas produced, net of production costs			(196,000	)		(206,000	)		(157,000	)
	Net changes in prices and production costs			(191,000	)		61,000			(201,000	)
	Purchases of minerals in place			—			106,000			205,000
	Sales of minerals in place			(6,000	)		(84,000	)		(49,000	)
	Previously estimated development costs incurred during			49,000			89,000			102,000
	the year
	Extensions, discoveries and improved recovery			207,000			111,000			105,000
	Changes in estimated future development costs			(13,000	)		(64,000	)		(102,000	)
	Revisions of previous quantity estimates			(16,000	)		(203,000	)		39,000
	Accretion of discount			89,000			79,000			77,000
	Net change in income taxes			44,000			67,000			72,000
	Changes in timing and other			(27,000	)		65,000			(35,000	)
	Standardized measure, end of year		$	833,000		$	893,000		$	872,000

Quarterly_Financial_Data_Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Data	The following is a summary of the unaudited financial data for each quarter for the years ended December 31, 2014 and 2013 (in thousands except per share data):
		Three Months Ended
		March 31,			June 30,			September 30,			December 31,
		2014			2014			2014			2014
	Year Ended December 31, 2014:
	Revenue	$	90,878		$	88,459		$	84,102		$	65,932
	Operating expenses		(79,803	)		(81,527	)		(81,384	)		(199,331	)
	Income (loss) from operations		11,075			6,932			2,718			(133,399	)
	Net income (loss)		(3,548	)		(16,120	)		14,966			(17,148	)
	Earnings (loss) per common share:
	Basic	$	(0.05	)	$	(0.22	)	$	0.2		$	(0.23	)
	Diluted	$	(0.05	)	$	(0.22	)	$	0.2		$	(0.23	)
	Weighted average common shares outstanding:
	Basic		73,540			73,843			73,886			73,917
	Diluted		73,540			73,843			74,050			73,917
		Three Months Ended
		March 31,			June 30,			September 30,			December 31,
		2013			2013			2013			2013
	Year Ended December 31, 2013:
	Revenue	$	78,897		$	89,116		$	89,085		$	92,681
	Operating expenses		(68,885	)		(74,389	)		(70,055	)		(270,318	)
	Income from operations		10,012			14,727			19,030			(177,637	)
	Net income (loss)		(3,049	)		9,023			(2,674	)		(117,106	)
	Earnings (loss) per common share:
	Basic	$	(0.05	)	$	0.14		$	(0.04	)	$	(1.60	)
	Diluted	$	(0.05	)	$	0.14		$	(0.04	)	$	(1.60	)
	Weighted average common shares outstanding:
	Basic		59,802			66,782			73,100			73,123
	Diluted		59,802			66,782			73,100			73,123

Basis_of_Presentation_and_Summ3

Basis of Presentation and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2012
	Segment
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Senior notes, principal	$400,000,000	$400,000,000
Senior notes, maturity	1-May-20
Secured term loan amount	150,000,000
Number of Operating Segments	1
Deferred financing cost	4,800,000	1,900,000	12,300,000
Deferred financing cost amortization interest expense	2,500,000	2,700,000	1,700,000
Capitalized Interest	14,900,000	15,900,000	4,700,000
Capitalized general and administrative and operating costs	9,800,000	8,400,000	6,000,000
Discount factor	10.00%	10.00%	10.00%
Impairment of proved oil and gas properties	120,000,000	188,000,000	0
Restricted cash	19,900,000
Future Net Revenue from Proved Oil and Gas Reserves
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Discount factor	10.00%
Minimum
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Unproved properties, evaluation time for existence of proved reserves	1 year
Minimum | Office furniture, automobiles, and computer hardware and software
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Property and equipment estimated useful life	3 years
Minimum | Field offices and partial ownership of aircraft
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Property and equipment estimated useful life	15 years
Maximum
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Unproved properties, evaluation time for existence of proved reserves	3 years
Maximum | Office furniture, automobiles, and computer hardware and software
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Property and equipment estimated useful life	5 years
Maximum | Field offices and partial ownership of aircraft
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Property and equipment estimated useful life	20 years
Revenue | Western Refining, Inc. | Customer Concentration Risk
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Concentration of credit risk percentage	62.00%	61.00%	78.00%
Revenue | Plains Marketing LP | Customer Concentration Risk
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Concentration of credit risk percentage	14.00%	15.00%
Senior Notes
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Senior notes, principal	400,000,000		150,000,000	250,000,000
Term Loan Facility | Second Lien
Organization And Summary Of Significant Accounting Policies Disclosure [Line Items]
Senior notes, maturity	31-Mar-18
Secured term loan amount	$150,000,000

Accounts_Receivable_Detail

Accounts Receivable (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Receivables [Abstract]
Trade receivables	$51,166	$92,959
Derivative receivables	6,638	866
Other receivables	105	533
Total accounts receivable	$57,909	$94,358

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended
	Mar. 22, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 27, 2013
Business Acquisition [Line Items]
Purchase agreement, purchase price of properties	$258,000,000		$258,000,000	$250,000,000
Purchase agreement, option fee to buy the balance of the working interest and field and operations				6,000,000
Effective date		1-Jan-12
Acquired interests		50.00%
Gain or loss recognized		0
Purchase and sales agreement with Halcón Resources Corporation
Business Acquisition [Line Items]
Purchase and sale agreement, effective date		1-Mar-13
Net proceeds received to dispose certain Bakken properties located in Williams County, North Dakota (the “New Home Properties”) and other non-operated Bakken properties					70,100,000
Transaction date		15-Jul-13
Aneth and Ratherford Units
Business Acquisition [Line Items]
Cash consideration for acquisitions		75,000,000
Purchase price allocated to proved oil and gas properties		37,700,000
Aneth Unit
Business Acquisition [Line Items]
Working interests		62.00%
Ratherford Unit
Business Acquisition [Line Items]
Working interests		59.00%
McElmo Creek Unit
Business Acquisition [Line Items]
Working interests, pre-acquisition		75.00%
McElmo Creek Unit | Scenario, Adjustment
Business Acquisition [Line Items]
Working interests		67.50%
Denbury Resources Inc Affiliates | Aneth Unit
Business Acquisition [Line Items]
Working interest acquired		13.00%
Denbury Resources Inc Affiliates | Ratherford Unit
Business Acquisition [Line Items]
Working interest acquired		11.00%
NNOGC
Business Acquisition [Line Items]
Acquired interests		50.00%
Cash consideration for acquisitions		100,000,000
Options to purchase		10.00%
Number of payments of property interest		2
Purchase and sale agreement relating to the option exercise		5.00%
Cancellation of purchase		10.00%
Number of purchase option remaining		1
Option exercisable		2017-07
Northwest Shelf Lea County NM And Spraberry Trend Midland Basin Permian Basin Howard County TX
Business Acquisition [Line Items]
Purchase agreement, purchase price of properties				117,000,000
Wolfberry Play Midland Basin Permian Basin Midland And Ector Counties TX
Business Acquisition [Line Items]
Purchase agreement, purchase price of properties				$133,000,000

Purchase_Price_of_Permian_Acqu

Purchase Price of Permian Acquisitions (Detail) (USD $)	0 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 22, 2013	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]
Purchase price	$258,000	$258,000	$250,000

Final_Purchase_Price_Allocatio

Final Purchase Price Allocation of Permian Acquisitions (Detail) (New Permian Properties, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Asset retirement obligations assumed	($2,000)	($3,000)
Total purchase price	258,000	250,000
Proved oil and gas properties
Business Acquisition [Line Items]
Oil and gas properties	93,000	131,000
Unproved oil and gas properties
Business Acquisition [Line Items]
Oil and gas properties	$167,000	$122,000

Unaudited_Pro_Forma_Financial_

Unaudited Pro Forma Financial Information (Detail) (New Permian Properties, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
New Permian Properties
Business Acquisition [Line Items]
Revenue	$360,837	$362,355
Revenue in excess of operating expenses	215,273	218,815
Net income (loss)	($111,243)	$30,381
Basic and diluted net income (loss) per share	($1.63)	$0.51

Weighted_Average_Dilutive_and_

Weighted Average Dilutive and Anti-Dilutive Securities (Detail)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Potential dilutive restricted stock	2,973	2,529	1,464
Anti-dilutive securities	27,523	35,569	37,779

Computation_of_Basic_and_Dilut

Computation of Basic and Diluted Net Income (Loss) Per Share of Common Stock (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share Diluted [Line Items]
Net income (loss)	($17,148)	$14,966	($16,120)	($3,548)	($117,106)	($2,674)	$9,023	($3,049)	($21,850)	($113,806)	$17,976
Basic weighted average common shares outstanding	73,917	73,886	73,843	73,540	73,123	73,100	66,782	59,802	73,798	68,260	59,424
Diluted weighted average common shares outstanding	73,917	74,050	73,843	73,540	73,123	73,100	66,782	59,802	73,798	68,260	59,452
Basic and diluted net income (loss) per common share									($0.30)	($1.67)	$0.30
Non-vested restricted stock
Earnings Per Share Diluted [Line Items]
Add: dilutive effect of non-vested restricted stock									0	0	28

Activity_Associated_with_Warra

Activity Associated with Warrants (Detail)	12 Months Ended
	Dec. 31, 2014	Sep. 25, 2014
Earnings Per Share [Abstract]
Beginning Balance	33,041,000	0
Expiration of public warrants	-33,041,000
Ending Balance	0	0

Longterm_Debt_Detail

Long-term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
Revolving credit facility	$235,000	$335,000
Secured term loan facility	150,000
Unamortized discount on secured term loan facility	-10,500
8.50% senior notes	400,000	400,000
Unamortized premium on senior notes	1,461	1,671
Total long-term debt	$775,961	$736,671

Longterm_Debt_Parenthetical_De

Long-term Debt (Parenthetical) (Detail)	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt instrument, interest rate	8.50%

Long_Term_Debt_Additional_Info

Long Term Debt - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2012	Mar. 07, 2014
Debt Instrument [Line Items]
Line of credit, borrowing base	$330,000,000
Secured debt to EBITDA ratio maximum	350.00%
Proved reserves to secured debt ratio, minimum	110.00%
Proved reserves to secured debt ratio, maximum	150.00%
Proved developed reserves to secured debt ratio, minimum	100.00%
Revolving credit facility interest rate terms	The London Interbank Offered Rate, plus a margin which varies from 1.50% to 2.50% (or 3.0% if the Company utilizes any portion of the non-conforming tranche) or (b) the alternative Base Rate defined as the greater of (i) the Administrative Agent’s Prime Rate (ii) the Federal Funds effective Rate plus 0.5% or (iii) an adjusted London Interbank Offered Rate (“LIBOR”) plus a margin which ranges from 0.50% to 1.50%
Outstanding borrowings	235,000,000
Borrowing base availability had been reduced	3,100,000
Borrowing base adjustment period	120 days
Weighted average interest rate on the outstanding balance under the Revolving Credit Facility	2.17%
Secured term loan amount	150,000,000
Expiration period of term loan after credit facility expiration	6 months
Percentage of mandatory net cash flow from sale of assets for prepayment of term loan with out premium	75.00%
Percentage of mandatory net cash flow from sale of securities for prepayment of term loan with premium	100.00%
Term loan prepayment period from closing date	36 months
Minimum debt ratio to invested capital for repayment of term loan	125.00%
Senior notes, principal	400,000,000	400,000,000
Senior notes, due date	1-May-20
Debt instrument, interest rate	8.50%
Senior Notes, redemption date	1-May-16
Proceeds from debt, net of issuance costs	139,500,000	0	401,875,000
Interest Expense on Long-term debt	46,400,000	45,200,000	20,200,000
Interest expense capitalized	14,900,000	15,900,000	4,700,000
Change of Control
Debt Instrument [Line Items]
Senior Notes, redemption price percentage of principal	101.00%
Option A
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				0.50%
Minimum
Debt Instrument [Line Items]
Percentage of Premium on prepayment of term loan.	10.00%
Senior Notes, redemption notice period	30 days
Minimum | Option A | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				1.50%
Maximum
Debt Instrument [Line Items]
Percentage of Premium on prepayment of term loan.	2.00%
Senior Notes, redemption notice period	60 days
Maximum | Option A | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				2.50%
Eleventh Amendment
Debt Instrument [Line Items]
Line of credit, borrowing base	330,000,000
Secured debt to EBITDA ratio maximum	350.00%
Proved reserves to secured debt ratio, minimum	110.00%
Proved reserves to secured debt ratio, maximum	150.00%
Proved developed reserves to secured debt ratio, minimum	100.00%
Revolving Credit Facility covenant description	The covenants require, among other things, maintenance of certain ratios, measured on a quarterly basis, as follows: (i) secured debt to EBITDA of no more than 3.5 to 1.0, (ii) PV-10 of total proved reserves to total secured debt of at least 1.1 to 1.0, rising over time to 1.5 to 1.0, and (iii) PV-10 of proved developed reserves to total secured debt of at least 1.0 to 1.0. Our Revolving Credit Facility and our Secured Term Loan Facility also require us to enter into derivative agreements covering at least 70% of our anticipated production from proved properties on a rolling twenty four month basis, but prohibit us from entering into derivative arrangements for more than (i) 85% of our anticipated production from proved properties in the next two years and (ii) the greater of 75% of our anticipated production from proved properties or 85% of our production from projected proved developed producing reserves using economic parameters specified in our Revolving Credit Facility.
Derivative agreement, percentage of anticipated production from proved properties, minimum	70.00%
Derivative agreement, percentage of anticipated production from proved properties, maximum	85.00%
Derivative agreement, percentage of projected proved developed producing reserves	85.00%
Anticipated production from proved properties period	2 years
Derivative agreement, percentage of anticipated production from proved properties	75.00%
Senior Notes
Debt Instrument [Line Items]
Senior notes, principal	400,000,000		150,000,000	250,000,000
Debt instrument, interest rate	8.50%
Senior Notes | Level 2
Debt Instrument [Line Items]
Senior Notes, fair value	194,000,000
Sixth Amendment
Debt Instrument [Line Items]
Revolving credit facility, maturity date	31-Mar-18
Option B, Option 3 | Minimum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				0.50%
Option B, Option 3 | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				1.50%
Secured Debt
Debt Instrument [Line Items]
Description of variable rate basis	Secured Term Loan Facility will bear interest at adjusted LIBOR plus 10%, with a 1% LIBOR floor.
Fixed interest rate on team loan facility	10.00%
Proceeds from debt, net of issuance costs	135,000,000
Secured Debt | Level 1
Debt Instrument [Line Items]
Senior Notes, fair value	$139,500,000
Fiscal quarter ending March 31, 2014 | Ninth Amendment
Debt Instrument [Line Items]
Maximum Leverage Ratio					490.00%
Fiscal quarters ending June 30, 2014 | Ninth Amendment
Debt Instrument [Line Items]
Maximum Leverage Ratio					490.00%
Fiscal quarters ending September 30, 2014 | Ninth Amendment
Debt Instrument [Line Items]
Maximum Leverage Ratio					475.00%
Fiscal quarters ending December 31, 2014 | Ninth Amendment
Debt Instrument [Line Items]
Maximum Leverage Ratio					475.00%
All quarters thereafter | Ninth Amendment
Debt Instrument [Line Items]
Maximum Leverage Ratio					400.00%
Last day of each fiscal quarter in 2014 | Ninth Amendment
Debt Instrument [Line Items]
Maximum Leverage Ratio					275.00%
Prior to May 1, 2015
Debt Instrument [Line Items]
Senior Notes, redeemable percentage of principal	35.00%
Senior Notes, redemption price percentage of principal	108.50%
Prior to May 1, 2016
Debt Instrument [Line Items]
Senior Notes, redemption price percentage of principal	100.00%

Components_of_Provision_for_In

Components of Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current income tax benefit (expense)	$0	$16	($16)
Deferred income tax benefit (expense)	4,140	64,663	-11,865
Total income tax benefit (expense)	$4,140	$64,679	($11,881)

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
U.S. federal income tax rate	35.00%	35.00%	35.00%
U.S. net operating loss carryforwards	$264,800,000
U.S. net operating loss carryforwards, beginning of expiration date	2026
Unrecognized tax benefits	0	0	0
Accrued interest or penalties related to uncertain tax positions	$0	$0	$0
Minimum | State Taxing Authorities
Income Taxes [Line Items]
Tax years open to examination	2010
Minimum | Internal Revenue Service
Income Taxes [Line Items]
Tax years open to examination	2011
Maximum | State Taxing Authorities
Income Taxes [Line Items]
Tax years open to examination	2014
Maximum | Internal Revenue Service
Income Taxes [Line Items]
Tax years open to examination	2014

Reconciliation_of_Provision_fo

Reconciliation of Provision for Income Taxes to Amount Provided by Applying Statutory United States Federal Income Tax Rate to Income Before Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Expected statutory income tax benefit (expense)	$9,097	$62,470	($10,450)
State income tax benefit (expense)	480	3,254	-694
Equity compensation	-4,273	-2,031	-703
Non-deductible executive compensation	-468	-54	-215
Other	-696	1,040	181
Total income tax benefit (expense)	$4,140	$64,679	($11,881)

Tax_Effects_of_Temporary_Diffe

Tax Effects of Temporary Differences that Give Rise to Significant Portions of Deferred Income Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current deferred income tax assets (liabilities):
Derivative financial instruments	($26,919)	$3,914
Asset retirement obligation	121	675
Equity compensation	2,803	2,924
Other	772	817
Total current assets (liabilities)	-23,223	8,330
Long term deferred income tax assets (liabilities):
Derivative financial instruments	-14,726	0
Net operating loss carryovers	97,022	62,457
Asset retirement obligation	11,475	11,161
Startup and organization costs	140	158
Deferred acquisition costs	45	45
Percentage depletion	1,341	1,323
Property and equipment costs	-95,378	-110,566
Equity compensation	1,144	1,233
Other	-194	-635
Total long term assets (liabilities)	869	-34,824
Net deferred tax liability	($22,354)	($26,494)

Stockholders_Equity_and_Equity2

Stockholders' Equity and Equity Based Awards - Preferred Stock - Additional Information (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, par value	$0.00	$0.00
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0

Stockholders_Equity_and_Equity3

Stockholder's Equity and Equity Based Awards - Common Stock - Additional Information (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Common stock, shares authorized	225,000,000	225,000,000
Common stock, shares issued	77,634,737	76,228,055
Common stock, shares outstanding	77,634,737	76,228,055
Number of votes per share of common stock	one vote for each share of common stock

Stockholders_Equity_and_Equity4

Stockholder's Equity and Equity Based Awards - Share-Based Compensation - Additional Information (Details) (USD $)	3 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 25, 2014	Jul. 31, 2009
Class Of Stock [Line Items]
Issuance of stock, net of underwriters discounts and commissions (in shares)	13,300,000
Issuance of common stock, price per share	$8
Proceeds from issuance of common stock, net of underwriters discounts and commissions	$101,800,000		$0	$101,760,000	$0
Warrants were repurchased		9,634,821	0	0
Warrants outstanding, shares			0	33,041,000			0
Retirement of public warrants		10,000,000	0	0	9,999,000
Average price of warrants		$1.04
Warrants Exercised			0	0	0
Investment Warrants Expiration Date Range End			25-Sep-14
Common stock								9,157,744
Time Based Restricted Stock Awards
Class Of Stock [Line Items]
Restricted stock to employees and directors granted			1,595,535	1,570,393	811,080
Share based compensation expense			12,100,000	11,000,000	7,200,000
Unrecognized compensation expense			16,700,000
Weighted-average period for unrecognized compensation expense			1 year 8 months 12 days
Time Based Restricted Stock Awards | Minimum
Class Of Stock [Line Items]
Vesting period			3 years
Estimated forfeiture rates			8.00%
Time Based Restricted Stock Awards | Maximum
Class Of Stock [Line Items]
Vesting period			4 years
Estimated forfeiture rates			10.00%
Stock Appreciation Awards
Class Of Stock [Line Items]
Vesting period			4 years
Restricted stock to employees and directors granted					316,008
Share based compensation expense			200,000	800,000	2,200,000
Unrecognized compensation expense			100,000
Weighted-average period for unrecognized compensation expense			1 year
Minimum appreciation over stock price for last year			10.00%
Number of trading days			20 days
Common Stock, Average stock price					$11.64	$14.23
Expired, Shares			156,793	390,174
Performance-based restricted shares
Class Of Stock [Line Items]
Restricted stock to employees and directors granted			487,819	354,517
Share based compensation expense			4,000,000	3,100,000
Unrecognized compensation expense			$4,500,000
Weighted-average period for unrecognized compensation expense			1 year 9 months 18 days
Number of Peer Companies			17
Number of installment for performance-Vested Shares vest			3
Performance-based restricted shares | First Installment
Class Of Stock [Line Items]
Vesting period			1 year
Performance-based restricted shares | Second Installment
Class Of Stock [Line Items]
Vesting period			2 years
Performance-based restricted shares | Third Installment
Class Of Stock [Line Items]
Vesting period			3 years
Performance-based restricted shares | Minimum
Class Of Stock [Line Items]
Estimated forfeiture rates			4.00%
Performance-based restricted shares | Maximum
Class Of Stock [Line Items]
Estimated forfeiture rates			15.00%

Changes_in_NonVested_Time_Base

Changes in Non-Vested Time Based Awards (Detail) (Time Based Restricted Stock Awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Time Based Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested, beginning of period, Shares	2,005,721	1,176,890	952,920
Granted, Shares	1,595,535	1,570,393	811,080
Vested, Shares	-819,615	-559,763	-543,593
Forfeited, Shares	-283,811	-181,799	-43,517
Non-vested, end of period, Shares	2,497,830	2,005,721	1,176,890
Non-vested, beginning of period, Weighted Average Grant Date Fair Value	$10.62	$12	$14.11
Granted, Weighted Average Grant Date Fair Value	$8.86	$10.31	$10.16
Vested, Weighted Average Grant Date Fair Value	$10.87	$12.47	$12.83
Forfeited, Weighted Average Grant Date Fair Value	$9.65	$11.15	$13.18
Non-vested, end of period, Weighted Average Grant Date Fair Value	$9.43	$10.62	$12

Changes_in_NonVested_Stock_App

Changes in Non-Vested Stock Appreciation Awards (Detail) (Stock Appreciation Awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Appreciation Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested, beginning of period, Shares	444,571	895,892	600,310
Granted, Shares			316,008
Forfeited, Shares	-21,126	-61,147	-20,426
Expired, Shares	-156,793	-390,174
Non-vested, end of period, Shares	266,652	444,571	895,892
Non-vested, beginning of period, Weighted Average Grant Date Fair Value	$7.60	$8.43	$10.71
Granted, Weighted Average Grant Date Fair Value			$4.02
Forfeited, Weighted Average Grant Date Fair Value	$7.04	$7.82	$7.56
Expired, Weighted Average Grant Date Fair Value	$13.89	$9.38
Non-vested, end of period, Weighted Average Grant Date Fair Value	$3.95	$7.60	$8.43

Valuation_Model_for_Performanc

Valuation Model for Performance-Based Awards (Detail) (Stock Performance Based Awards)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Performance Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average Expected Volatility, Minimum			32.10%
Average Expected Volatility, Maximum			33.00%
Average Expected Volatility	39.40%	35.00%
Expected Dividend Yield	0.00%	0.00%	0.00%
Risk-Free Interest Rate, Minimum			0.56%
Risk Free Interest Rate, Maximum			0.85%
Risk-Free Interest Rate	0.69%	0.42%

Changes_in_NonVested_TSR_Award

Changes in Non-Vested TSR Awards (Detail) (Performance-based restricted shares, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Performance-based restricted shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested, beginning of period, Shares	340,166	0
Granted, Shares	487,819	354,517
Vested, Shares	-63,387	0
Forfeited, Shares	0	-14,351
Non-vested, end of period, Shares	764,598	340,166
Non-vested, beginning of period, Weighted Average Grant Date Fair Value	$15.91	$0
Granted, Weighted Average Grant Date Fair Value	$13.32	$15.91
Vested, Weighted Average Grant Date Fair Value	$15.91	$0
Forfeited, Weighted Average Grant Date Fair Value	$0	$15.91
Non-vested, end of period, Weighted Average Grant Date Fair Value	$14.26	$15.91

Asset_Retirement_Obligation_Ad

Asset Retirement Obligation - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014
Minimum
Asset Retirement Obligations [Line Items]
Credit-adjusted risk-free discounted rate	7.00%
Maximum
Asset Retirement Obligations [Line Items]
Credit-adjusted risk-free discounted rate	12.00%

Reconciliation_of_Asset_Retire

Reconciliation of Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$31,989	$19,155
Additional liability incurred / acquired	144	2,165
Accretion expense	2,576	1,327
Liabilities settled	-1,282	-1,573
Revisions to previous estimates	-2,087	10,915
Asset retirement obligations at end of period	31,340	31,989
Less: current asset retirement obligations	-327	-1,825
Long-term asset retirement obligations	$31,013	$30,164

Derivative_Instruments_Additio

Derivative Instruments - Additional information (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Derivative [Line Items]
Maximum amount of loss in the event of all counterparties defaulting	$112.60
Level 2 | Commodity Contract
Derivative [Line Items]
Fair value of commodity derivatives net liability	$112.60

Oil_and_Gas_Commodity_Contract

Oil and Gas Commodity Contracts (Detail) (Commodity Contract)	Dec. 31, 2014
	bbl
Oil (NYMEX WTI) | Jan – Dec 2016
Derivative [Line Items]
Bbl per Day	6,500
Weighted Average Swap Price per Bbl	80.42
Oil (NYMEX WTI) | Jan – Dec 2015
Derivative [Line Items]
Bbl per Day	5,600
Weighted Average Swap Price per Bbl	86.8
Gas (NYMEX HH) | Jan – Dec 2015
Derivative [Line Items]
Bbl per Day	12,600
Weighted Average Swap Price per Bbl	3.635

Commodity_Collar_Contracts_Det

Commodity Collar Contracts (Detail) (Commodity Contract)	Dec. 31, 2014
	bbl
Oil (NYMEX WTI) | Jan – Dec 2015
Derivative [Line Items]
Bbl per Day	5,600
Oil (NYMEX WTI) | Two-Way Commodity Collar | Jan – Dec 2015
Derivative [Line Items]
Bbl per Day	1,000
Weighted Average Floor Price	84.17
Weighted Average Ceiling Price	92.1
Gas (NYMEX HH) | Jan – Dec 2015
Derivative [Line Items]
Bbl per Day	12,600
Gas (NYMEX HH) | Three-Way Gas Collar | Jan – Mar 2015
Derivative [Line Items]
Bbl per Day	5,000
Weighted Average Floor Price	4.5
Weighted Average Ceiling Price	5.55
Weighted Average Short Put Price Per MMBtu	3.75

Amount_of_Commodity_Derivative

Amount of Commodity Derivative Instrument Gains Losses (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Commodity derivative settlements	($4,988)	($35,812)	($22,920)
Mark-to-market gain	123,129	20,476	28,096
Commodity derivative instruments gain (loss)	$118,141	($15,336)	$5,176

Assets_and_Liabilities_Require

Assets and Liabilities Required to be Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets
Derivative instruments, current assets	$72,753	$1,378
Derivative instruments, long term assets	39,799	0
Liabilities
Derivative instruments, current liabilities	0	11,955
Fair Value Measurements Recurring Basis | Level 2 | Commodity
Assets
Derivative instruments, current assets	72,753	1,378
Derivative instruments, long term assets	39,799
Total assets	112,552	1,378
Liabilities
Derivative instruments, current liabilities		11,955
Total liabilities		$11,955

Future_Minimum_COTwo_Purchase_

Future Minimum COTwo Purchase Commitments (Detail) (Co2 Kinder Morgan company, USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Co2 Kinder Morgan company
Recorded Unconditional Purchase Obligation [Line Items]
2015	$13,499
2016	12,408
2017	561
Total	$26,468

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2012
Commitment And Contingencies [Line Items]
Rental expense, net	$2.60	$2.90	$2.60
NNOGC
Commitment And Contingencies [Line Items]
Percentage of interest that each purchase options entitles to purchase	10.00%
NNOGC | Aneth Field Properties
Commitment And Contingencies [Line Items]
Percentage of ownership interest sold				10.00%
NNOGC | Chevron Properties
Commitment And Contingencies [Line Items]
Number of purchase options	3
Office facilities
Commitment And Contingencies [Line Items]
Rental expense, net	1.6	2	1.5
Escrow Funding Agreement
Commitment And Contingencies [Line Items]
Funding amount in 2015	1.6
Funding amount in 2016	1.6
Aggregate funding commitment	26
Annual contractual amount funded	1.6
Escrow Funding Agreement | Additional Payments Per Year Until 2031
Commitment And Contingencies [Line Items]
Aggregate funding commitment	$0.90

Schedule_of_Future_Payment_Ope

Schedule of Future Payment Operating Leases Agreements (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Operating Leases Future Minimum Payments Due [Abstract]
2015	$4,839
2016	4,078
2017	3,531
2018 and thereafter	6,277
Total	18,725
Office Lease Rentals
Operating Leases Future Minimum Payments Due [Abstract]
2015	1,525
2016	1,764
2017	1,700
2018 and thereafter	5,950
Total	10,939
Field Equipment Rentals
Operating Leases Future Minimum Payments Due [Abstract]
2015	2,094
2016	1,637
2017	1,473
2018 and thereafter	245
Total	5,449
Vehicle Lease Rentals
Operating Leases Future Minimum Payments Due [Abstract]
2015	1,220
2016	677
2017	358
2018 and thereafter	82
Total	$2,337

Costs_Incurred_in_Oil_and_Gas_

Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Acquisition costs
Proved			$155,958		$166,951
Unproved	7,007		121,362		125,059
Exploration costs	111,769		150,072		120,570
Development costs	50,291	[1]	97,308	[1]	100,579	[1]
Total	$169,067		$524,700		$513,159
[1]	Includes $16.3 million, $20.0 million and $16.2 million of acquired CO2 during 2014, 2013 and 2012, respectively.

Costs_Incurred_in_Oil_and_Gas_1

Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Acquired CO2	$16.30	$20	$16.20

Net_Capitalized_Costs_Related_

Net Capitalized Costs Related to Resolute's Oil and Gas Producing Activities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property Plant And Equipment [Abstract]
Proved oil and gas properties	$1,706,847	$1,544,942
Unevaluated oil and gas properties, not subject to amortization	270,375	274,420
Accumulated depletion, depreciation and amortization	-738,979	-491,279
Oil and gas properties, net	$1,238,243	$1,328,083

Changes_in_Estimated_Reserves_

Changes in Estimated Reserves (Detail)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	Boe		Boe		Boe
Oil Equivalent
Reserve Quantities [Line Items]
Proved reserves, beginning balance	59,394,000	[1]	78,774,000	[1]	64,798,000	[1]
Purchase of minerals in place			7,818,000	[1]	13,374,000	[1]
Production	-4,647,000	[1]	-4,467,000	[1]	-3,409,000	[1]
Extensions, discoveries and other additions					4,924,000	[1],[2]
Sales of minerals in place	-224,000	[1]	-5,906,000	[1]	-2,717,000	[1]
Revisions of previous estimates	-9,105,000	[1]	-22,630,000	[1]	1,804,000	[1]
Proved reserves, ending balance	74,218,000	[1]	59,394,000	[1]	78,774,000	[1]
Extensions, discoveries and other additions	28,800,000	[1],[2]	5,805,000	[1],[2]
Proved developed reserves	41,446,000	[1]	46,842,000	[1]	46,217,000	[1]
Proved undeveloped reserves	32,772,000	[1]	12,552,000	[1]	32,557,000	[1]
Oil
Reserve Quantities [Line Items]
Proved reserves, beginning balance	47,511,000		62,557,000		52,841,000
Purchase of minerals in place			4,592,000		9,463,000
Production	-3,489,000	[2]	-3,499,000		-2,773,000
Extensions, discoveries and other additions	25,756,000		4,038,000	[2]	4,115,000	[2]
Sales of minerals in place	-215,000		-5,124,000		-2,391,000
Revisions of previous estimates	-5,848,000		-15,053,000	[3]	1,302,000
Proved reserves, ending balance	63,715,000		47,511,000		62,557,000
Proved developed reserves	34,359,000		38,791,000		39,288,000
Proved undeveloped reserves	29,356,000		8,720,000		23,268,000
Gas
Reserve Quantities [Line Items]
Proved reserves, beginning balance	42,389,000		47,721,000		35,157,000
Purchase of minerals in place			10,821,000		10,375,000
Production	-6,942,000	[2]	-4,565,000		-3,567,000
Extensions, discoveries and other additions	10,128,000		6,128,000	[2]	3,400,000	[2]
Sales of minerals in place	-26,000		-3,379,000		-735,000
Revisions of previous estimates	-8,751,000		-14,337,000	[3]	3,091,000
Proved reserves, ending balance	36,798,000		42,389,000		47,721,000
Proved developed reserves	25,775,000		29,488,000		25,568,000
Proved undeveloped reserves	11,023,000		12,901,000		22,153,000
NGL
Reserve Quantities [Line Items]
Proved reserves, beginning balance	4,817,000		8,264,000		6,097,000
Purchase of minerals in place			1,422,000		2,182,000
Production			-207,000		-41,000
Extensions, discoveries and other additions	1,357,000		746,000	[2]	243,000	[2]
Sales of minerals in place	-5,000		-219,000		-203,000
Revisions of previous estimates	-1,799,000		-5,189,000	[3]	-14,000
Proved reserves, ending balance	4,370,000		4,817,000		8,264,000
Proved developed reserves	2,791,000		3,136,000		2,668,000
Proved undeveloped reserves	1,579,000		1,681,000		5,596,000
[1]	In accordance with SEC and Financial Accounting Standards Board (“FASB”) requirements, our estimated net proved reserves and standardized measure at December 31, 2014 and 2013, utilized prices (subsequently adjusted for quality and basis differentials) of an average NYMEX West Texas Intermediate oil price of $94.99 and $96.94 per Bbl for the Aneth Properties and Plains Marketing, L.P. West Texas Intermediate oil price of $91.48 and $93.42 per Bbl for the Permian and Wyoming Properties, and an average Henry Hub spot marketing gas price of $4.35 and $3.67 per one MMBtu of gas, respectively. At December 31, 2012, we used an average NYMEX West Texas Intermediate oil price of $94.71 per Bbl, and an average Henry Hub spot market gas price of $2.76 per MMBtu.
[2]	Extensions, discoveries and other additions in 2014 are primarily associated with reinstatement of CO2 enhanced recovery projects that were removed for year-end 2013 reporting to comply with the SEC five-year rule pertaining to undeveloped reserves. Approximately 21.1 MMBoe have been reinstated as proved undeveloped all comprised of four named CO2 injection projects identified in the Aneth Field Properties: 8.9 MMBoe for Aneth Unit Phase 4 CO2 injection, 3.0 MMBoe for McElmo Unit DCIIC CO2 injection, 4.9 MMBoe for Ratherford DCIA CO2 injection and 4.3 MMBoe for Ratherford DCIIC CO2 injection. Additionally, the Permian and Powder River Basin properties held active drilling programs in 2014 resulting in 1.7 MMBoe added to proved developed producing from successful drilling of non-proved locations. Furthermore, these successful wells created additional proved undeveloped offset locations carrying 6.0 MMBoe reserves.
[3]	Decreases in proved reserves associated with revisions of previous estimates resulted from management’s decision to allocate more of its 2014 capital expenditures towards exploitation drilling of higher expected rates-of-return horizontal wells in the Permian Basin and less capital towards development projects in Aneth Field. Deferral of these projects to 2015 and beyond decreased proved undeveloped reserves by approximately 25 MMBoe, as these projects were no longer expected to be converted to developed reserves within five years after their initial recognition as proved reserves as required under SEC rules, offset by approximately 3 MMBoe converted to proved developed during 2013. The deferred will be again eligible as proved undeveloped reserves in the future, at such time as management adopts a definitive plan to complete the projects.

Changes_in_Estimated_Reserves_1

Changes in Estimated Reserves (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil | NYMEX West Texas
Reserve Quantities [Line Items]
Average oil and gas market price	94.99	96.94	94.71
Oil | Plains Marketing, L.P. West Texas
Reserve Quantities [Line Items]
Average oil and gas market price	91.48	93.42
Gas | Henry Hub
Reserve Quantities [Line Items]
Average oil and gas market price	4.35	3.67	2.76
Proved undeveloped reserves
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	21,100,000
Period for converting proved undeveloped locations to proved developed properties	5 years
Proved developed and undeveloped reserves extensions discoveries reductions		25,000,000
Proved developed and undeveloped reserves extensions discoveries additions		3,000,000
Proved undeveloped reserves | Aneth Unit Phase 4 CO2 injection
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	8,900,000
Proved undeveloped reserves | McElmo Unit DCIIC CO2 injection
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	3,000,000
Proved undeveloped reserves | Ratherford DCIA CO2 injection
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	4,900,000
Proved undeveloped reserves | Ratherford DCIIC CO2 injection
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	4,300,000
Proved undeveloped reserves | Permian and Powder River Basin
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	1,700,000
Proved undeveloped reserves | Additional proved undeveloped offset locations
Reserve Quantities [Line Items]
Reinstatements (additions) of estimated proved undeveloped reserves	6,000,000

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Discount factor	10.00%	10.00%	10.00%

Future_Net_Cash_Flows_Relating

Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Future cash inflows	$5,858,000	$4,647,000	$5,983,000
Future production costs	-2,719,000	-2,050,000	-2,678,000
Future development costs	-1,008,000	-547,000	-832,000
Future income taxes	-412,000	-398,000	-645,000
Future net cash flows	1,719,000	1,652,000	1,828,000
10% annual discount for estimated timing of cash flows	-886,000	-759,000	-956,000
Standardized measure of discounted future net cash flows	$833,000	$893,000	$872,000	$816,000

Future_Net_Cash_Flows_Relating1

Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Discount factor	10.00%	10.00%	10.00%

Principal_Sources_of_Change_in

Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Standardized measure, beginning of year	$893,000	$872,000	$816,000
Sales of oil and gas produced, net of production costs	-196,000	-206,000	-157,000
Net changes in prices and production costs	-191,000	61,000	-201,000
Purchases of minerals in place		106,000	205,000
Sales of minerals in place	-6,000	-84,000	-49,000
Previously estimated development costs incurred during the year	49,000	89,000	102,000
Extensions, discoveries and improved recovery	207,000	111,000	105,000
Changes in estimated future development costs	-13,000	-64,000	-102,000
Revisions of previous quantity estimates	-16,000	-203,000	39,000
Accretion of discount	89,000	79,000	77,000
Net change in income taxes	44,000	67,000	72,000
Changes in timing and other	-27,000	65,000	-35,000
Standardized measure, end of year	$833,000	$893,000	$872,000

Quarterly_Financial_Data_unaud

Quarterly Financial Data (unaudited) (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Revenue	$65,932	$84,102	$88,459	$90,878	$92,681	$89,085	$89,116	$78,897
Operating expenses	-199,331	-81,384	-81,527	-79,803	-270,318	-70,055	-74,389	-68,885	-442,045	-483,647	-218,084
Income (loss) from operations	-133,399	2,718	6,932	11,075	-177,637	19,030	14,727	10,012	-112,674	-133,868	40,184
Net income (loss)	($17,148)	$14,966	($16,120)	($3,548)	($117,106)	($2,674)	$9,023	($3,049)	($21,850)	($113,806)	$17,976
Net income (loss) per common share:
Basic	($0.23)	$0.20	($0.22)	($0.05)	($1.60)	($0.04)	$0.14	($0.05)
Diluted	($0.23)	$0.20	($0.22)	($0.05)	($1.60)	($0.04)	$0.14	($0.05)
Weighted average common shares outstanding:
Basic	73,917	73,886	73,843	73,540	73,123	73,100	66,782	59,802	73,798	68,260	59,424
Diluted	73,917	74,050	73,843	73,540	73,123	73,100	66,782	59,802	73,798	68,260	59,452