Stone Energy (SGY) 10-K 27 Feb 14 2013 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, 2013	Feb. 25, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'SGY	'	'
Entity Registrant Name	'STONE ENERGY CORP	'	'
Entity Central Index Key	'0000904080	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	49,790,620	'
Entity Public Float	'	'	$961.60

CONSOLIDATED_BALANCE_SHEET

CONSOLIDATED BALANCE SHEET (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'		'
Cash and cash equivalents	$331,224		$279,526
Accounts receivable	171,971		167,288
Fair value of hedging contracts	4,549		39,655
Current income tax receivable	7,366		10,027
Deferred taxes	31,710	[1]	15,514	[1]
Inventory	3,723		4,207
Other current assets	1,874		3,626
Total current assets	552,417		519,843
Oil and gas properties, full cost method of accounting:	'		'
Proved	7,804,117		7,244,466
Less: accumulated depreciation, depletion and amortization	-5,908,760		-5,510,166
Net proved oil and gas properties	1,895,357		1,734,300
Unevaluated	724,339		447,795
Other property and equipment, net of accumulated depreciation of $21,748 and $26,429, respectively	26,178		22,115
Fair value of hedging contracts	1,378		9,199
Other assets, net of accumulated depreciation and amortization of $5,768 and $6,438, respectively	48,887		43,179
Total assets	3,248,556		2,776,431
Current liabilities:	'		'
Accounts payable to vendors	195,677		94,361
Undistributed oil and gas proceeds	37,029		23,414
Accrued interest	9,022		18,546
Fair value of hedging contracts	7,753		149
Asset retirement obligations	67,161		66,260
Other current liabilities	54,520		16,765
Total current liabilities	371,162		219,495
Long-term debt	1,027,084		914,126
Deferred taxes	390,693	[1]	310,830	[1]
Asset retirement obligations	435,352		422,042
Fair value of hedging contracts	470		1,530
Other long-term liabilities	53,509		36,275
Total liabilities	2,278,270		1,904,298
Commitments and contingencies	'		'
Stockholders' equity:	'		'
Common stock, $.01 par value; authorized 100,000,000 shares; issued 48,750,533 and 48,392,552 shares, respectively	488		484
Treasury stock (16,582 shares, at cost)	-860		-860
Additional paid-in capital	1,397,885		1,386,475
Accumulated deficit	-425,165		-542,799
Accumulated other comprehensive income (loss)	-2,062		28,833
Total stockholders' equity	970,286		872,133
Total liabilities and stockholders' equity	$3,248,556		$2,776,431
[1]	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.

CONSOLIDATED_BALANCE_SHEET_Par

CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement Of Financial Position [Abstract]	'	'
Other property and equipment, accumulated depreciation	$21,748	$26,429
Other assets, accumulated depreciation and amortization	$5,768	$6,438
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	48,750,533	48,392,552
Treasury stock, shares	16,582	16,582

CONSOLIDATED_STATEMENT_OF_INCO

CONSOLIDATED STATEMENT OF INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenue:	'	'	'
Oil production	$715,104	$761,304	$663,958
Gas production	190,580	134,739	170,611
Natural gas liquids production	60,687	48,498	29,996
Other operational income	7,808	3,520	3,938
Derivative income, net	'	3,428	1,418
Total operating revenue	974,179	951,489	869,921
Operating expenses:	'	'	'
Lease operating expenses	201,153	215,003	175,881
Transportation, processing and gathering expenses	42,172	21,782	8,958
Production taxes	15,029	10,015	9,380
Depreciation, depletion and amortization	350,574	344,365	280,020
Accretion expense	33,575	33,331	30,764
Salaries, general and administrative expenses	59,524	54,648	40,169
Franchise tax settlement	12,590	'	'
Incentive compensation expense	15,340	8,113	11,600
Other operational expenses	151	267	2,149
Derivative expense, net	2,090	'	'
Total operating expenses	732,198	687,524	558,921
Income from operations	241,981	263,965	311,000
Other (income) expenses:	'	'	'
Interest expense	32,837	30,375	9,289
Interest income	-1,695	-600	-420
Other income	-2,799	-1,805	-1,942
Loss on early extinguishment of debt	27,279	1,972	607
Total other (income) expenses	55,622	29,942	7,534
Income before income taxes	186,359	234,023	303,466
Provision (benefit) for income taxes:	'	'	'
Current	-10,904	15,022	-20,386
Deferred	79,629	69,575	129,520
Total income taxes	68,725	84,597	109,134
Net income	$117,634	$149,426	$194,332
Basic earnings per share	$2.36	$3.03	$3.97
Diluted earnings per share	$2.36	$3.03	$3.97
Average shares outstanding	48,693	48,319	47,988
Average shares outstanding assuming dilution	48,735	48,361	48,030

CONSOLIDATED_STATEMENT_OF_COMP

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Statement Of Income And Comprehensive Income [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Net income

$1,752

[1],[2]

$36,102

$39,022

$40,758

$44,246

$23,659

$30,547

$50,974

$117,634

$149,426

$194,332

Other comprehensive income (loss) net of tax effect:

'

'

'

'

'

'

'

'

'

'

'

Derivatives

'

'

'

'

'

'

'

'

-30,228

6,965

36,072

Foreign currency translation

'

'

'

'

'

'

'

'

-667

'

'

Comprehensive income

'

'

'

'

'

'

'

'

$86,739

$156,391

$230,404

[1]

Includes franchise tax settlement of $12,590 before income tax effect ($8,058, net of income tax effect).

[2]

Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

CONSOLIDATED_STATEMENT_OF_CASH

CONSOLIDATED STATEMENT OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income	$117,634	$149,426	$194,332
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	350,574	344,365	280,020
Accretion expense	33,575	33,331	30,764
Deferred income tax provision	79,629	69,575	129,520
Settlement of asset retirement obligations	-83,854	-65,567	-63,391
Non-cash stock compensation expense	10,347	8,699	5,905
Excess tax benefits	-156	-949	-1,493
Non-cash derivative expense (income)	2,239	-509	-2,216
Loss on early extinguishment of debt	27,279	1,972	607
Non-cash interest expense	16,219	13,085	1,908
Other non-cash income	'	'	-1,602
Change in current income taxes	2,767	10,618	-19,451
Increase in accounts receivable	-4,683	-55,871	-19,600
(Increase) decrease in other current assets	1,752	-2,836	-66
Decrease in inventory	583	436	1,619
Increase in accounts payable	402	5,101	6,039
Increase (decrease) in other current liabilities	42,451	-10,426	29,583
Other	-2,553	9,299	-1,628
Net cash provided by (used in) operating activities	594,205	509,749	570,850
Cash flows from investing activities:	'	'	'
Investment in oil and gas properties	-663,299	-555,855	-764,933
Proceeds from sale of oil and gas properties, net of expenses	48,821	403	87,930
Sale of fixed assets	'	134	'
Investment in fixed and other assets	-6,816	-13,370	-2,247
Change in restricted funds	-1,742	'	'
Net cash used in investing activities	-623,036	-568,688	-679,250
Cash flows from financing activities:	'	'	'
Proceeds from bank borrowings	'	25,000	75,000
Repayments of bank borrowings	'	-70,000	-30,000
Proceeds from issuance of senior convertible notes	'	300,000	'
Deferred financing costs of senior convertible notes	'	-8,855	'
Proceeds from sold warrants	'	40,170	'
Payments for purchased call options	'	-70,830	'
Proceeds from issuance of senior notes	489,250	300,000	'
Deferred financing costs	-9,065	-11,966	-4,017
Redemption of senior notes	-396,014	'	'
Redemption of senior subordinated notes	'	-200,681	'
Excess tax benefits	156	949	1,493
Net payments for share-based compensation	-3,733	-3,773	-2,581
Net cash provided by financing activities	80,594	300,014	39,895
Effect of exchange rate changes on cash	-65	'	'
Net change in cash and cash equivalents	51,698	241,075	-68,505
Cash and cash equivalents, beginning of period	279,526	38,451	106,956
Cash and cash equivalents, end of period	331,224	279,526	38,451
Supplemental cash flow information:	'	'	'
Interest, net of amount capitalized	-29,883	-20,150	-9,808
Income taxes	$13,670	($4,405)	$935

CONSOLIDATED_STATEMENT_OF_CHAN

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $)	Total	Common Stock	Treasury Stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)
In Thousands
Beginning Balance at Dec. 31, 2010	$430,357	$478	($860)	$1,331,500	($886,557)	($14,204)
Net income	194,332	'	'	'	194,332	'
Adjustment for fair value accounting of derivatives, net of tax	36,072	'	'	'	'	36,072
Exercise of stock options and vesting of restricted stock	-2,581	3	'	-2,584	'	'
Amortization of stock compensation expense	8,914	'	'	8,914	'	'
Net tax impact from stock option exercises and restricted stock vesting	735	'	'	735	'	'
Ending Balance at Dec. 31, 2011	667,829	481	-860	1,338,565	-692,225	21,868
Net income	149,426	'	'	'	149,426	'
Adjustment for fair value accounting of derivatives, net of tax	6,965	'	'	'	'	6,965
Exercise of stock options and vesting of restricted stock	-3,773	3	'	-3,776	'	'
Amortization of stock compensation expense	12,792	'	'	12,792	'	'
Net tax impact from stock option exercises and restricted stock vesting	814	'	'	814	'	'
Convertible notes offering	38,080	'	'	38,080	'	'
Ending Balance at Dec. 31, 2012	872,133	484	-860	1,386,475	-542,799	28,833
Net income	117,634	'	'	'	117,634	'
Adjustment for fair value accounting of derivatives, net of tax	-30,228	'	'	'	'	-30,228
Adjustment for foreign currency translation, net of tax	-667	'	'	'	'	-667
Exercise of stock options and vesting of restricted stock	-3,126	4	'	-3,130	'	'
Amortization of stock compensation expense	15,424	'	'	15,424	'	'
Net tax impact from stock option exercises and restricted stock vesting	-884	'	'	-884	'	'
Ending Balance at Dec. 31, 2013	$970,286	$488	($860)	$1,397,885	($425,165)	($2,062)

ORGANIZATION_AND_SUMMARY_OF_SI

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
	Stone Energy Corporation (“Stone”) is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. We have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. We have expanded our reserve base outside of the conventional shelf of the Gulf of Mexico (the “GOM”) and into the more prolific reserve basins of the GOM deep water and GOM deep gas, as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.
	A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.
	Basis of Presentation:
	The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”), Stone Energy Holding, L.L.C., Stone Energy Canada, U.L.C. and Caillou Boca Gathering, LLC (“Caillou Boca”). On September 6, 2012, Caillou Boca was merged into Stone Offshore. All intercompany balances have been eliminated.
	Use of Estimates:
	The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative positions, the purchase price allocation on properties acquired, estimates of fair value in business combinations and contingencies.
	Fair Value Measurements:
	U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2013 and 2012, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. Additionally, fair value concepts were applied in recording the acquisition of various deep water assets in June 2012 and the acquisition of an office building in December 2012.
	Hybrid Debt Instruments:
	In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”). See Note 11 – Long-Term Debt. On that same day we entered into convertible note hedging transactions which are expected to reduce the potential dilution to our common stock upon conversion of the notes. In accordance with Accounting Standards Codification (“ASC”) 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that will reflect our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as part of interest expense. Additionally, the hedging transactions meet the criteria for classification as equity transactions and were recorded as such.
	ASC 260 provides that for contracts that may be settled in common stock or in cash at the election of the entity or the holder, the determination of whether the contract shall be reflected in the computation of diluted earnings per share should be made based on the facts available each period. It is presumed that the contract will be settled in common stock and therefore potential dilution be determined using the if-converted method. However, this presumption may be overcome if past experience or a stated policy provides a reasonable basis to believe that the contract will be settled partially or wholly in cash. Because it is management’s stated intent to redeem the principal amount of the notes in cash, we have used the treasury stock method for determining potential dilution of the notes in our diluted earnings per share computation in accordance with ASC 260.
	Business Combinations:
	Our acquisition in 2012 of various deep water assets was accounted for according to the guidance provided in ASC 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value. Differences between the net fair value of net assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain.
	Cash and Cash Equivalents:
	We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.
	Oil and Gas Properties:
	We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.
	U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs and in the computation of DD&A expense. Under the full cost method, all exploratory costs are capitalized while under the successful efforts method exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries while under the successful efforts method cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs.
	We amortize our investment in oil and gas properties through DD&A expense using the units of production (the “UOP”) method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of the period reserves being determined by adding back production to end of the period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.
	Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows.
	Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
	Asset Retirement Obligations:
	U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.
	Other Property and Equipment:
	Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful life of 39 years.
	Inventory:
	We maintain an inventory of tubular goods. Items remain in inventory until dedicated to specific projects, at which time they are transferred to oil and gas properties. Items are carried at the lower of cost or market based on the specific identification method.
	Earnings Per Common Share:
	Under U.S. GAAP, certain instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.
	Production Revenue:
	We recognize production revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production.
	Income Taxes:
	Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures, including future abandonment costs, related to evaluated projects are capitalized and depreciated, depleted and amortized on the UOP method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion, although for 2011, 2012 and 2013, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.
	Derivative Instruments and Hedging Activities:
	The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments that qualify for cash flow hedge accounting treatment with contemporaneous documentation are recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operations. Instruments not qualifying for hedge accounting treatment are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income).
	Share-Based Compensation:
	We record share-based compensation based on the grant date fair value of issued stock options and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of restricted shares is typically determined based on the average of our high and low stock prices on the grant date.

EARNINGS_PER_SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
EARNINGS PER SHARE	'
	NOTE 2 — EARNINGS PER SHARE:
	The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:
		Year Ended December 31,
		2013			2012			2011
	Income (numerator):
	Basic:
	Net income	$	117,634		$	149,426		$	194,332
	Net income attributable to participating securities		(2,817	)		(2,984	)		(3,670	)
	Net income attributable to common stock—basic	$	114,817		$	146,422		$	190,662
	Diluted:
	Net income	$	117,634		$	149,426		$	194,332
	Net income attributable to participating securities		(2,815	)		(2,982	)		(3,667	)
	Net income attributable to common stock—diluted	$	114,819		$	146,444		$	190,665
	Weighted average shares (denominator):
	Weighted average shares—basic		48,693			48,319			47,988
	Dilutive effect of stock options		42			42			42
	Weighted average shares—diluted		48,735			48,361			48,030
	Basic earnings per share	$	2.36		$	3.03		$	3.97
	Diluted earnings per share	$	2.36		$	3.03		$	3.97
	Stock options that were considered antidilutive because the exercise price of the options exceeded the average price of our common stock for the applicable period totaled approximately 242,000, 347,000 and 374,000 shares during the years ended December 31, 2013, 2012 and 2011, respectively.
	During the years ended December 31, 2013, 2012 and 2011, approximately 358,000, 316,000 and 312,000 shares of our common stock, respectively, were issued from authorized shares upon the vesting (lapse of forfeiture restrictions) of restricted stock by employees and nonemployee directors.
	Because it is management’s stated intention to redeem the principal amount of our 2017 Convertible Notes (see Note 11 – Long-Term Debt) in cash, we have used the treasury method for determining potential dilution in the diluted earnings per share computation. Since the average price of our common stock was less than the effective conversion price for such notes during the years ended December 31, 2013 and 2012, the 2017 Convertible Notes were not dilutive for such periods. Additionally, since the average price of our common stock was less than the strike price of the Sold Warrants (as defined in Note 11 – Long-Term Debt) for the years ended December 31, 2013 and 2012, such warrants were also not dilutive for such periods.

ACCOUNTS_RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2013
Receivables [Abstract]	'
ACCOUNTS RECEIVABLE	'
	NOTE 3 — ACCOUNTS RECEIVABLE:
	In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts:
		As of December 31,
		2013		2012
	Other co-venturers	$	13,904	$	16,735
	Trade		134,622		130,448
	Unbilled accounts receivable		22,001		20,053
	Other		1,444		52
	Total accounts receivable	$	171,971	$	167,288

CONCENTRATIONS

CONCENTRATIONS	12 Months Ended
	Dec. 31, 2013
Risks And Uncertainties [Abstract]	'
CONCENTRATIONS	'
	NOTE 4 — CONCENTRATIONS:
	Sales to Major Customers
	Our production is sold on month-to-month contracts at prevailing prices. We obtain credit protections such as parental guarantees from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our total oil and gas revenue during the years ended:
			December 31,
			2013			2012			2011
	Conoco, Inc.			(a	)		13	%		28	%
	Phillips 66 Company			35	%		18	%		(a	)
	Shell Trading (US) Company			33	%		41	%		46	%
	(a)	Less than 10 percent.
	The maximum amount of credit risk exposure at December 31, 2013 relating to these customers amounted to $74,273.
	We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and gas production.
	Production and Reserve Volumes- Unaudited
	Approximately 16% of our estimated proved reserves at December 31, 2013 and 49% of our production during 2013 were associated with our Gulf Coast Basin conventional shelf and deep gas properties. Approximately 29% of our estimated proved reserves at December 31, 2013 and 25% of our production during 2013 were associated with our deep water properties. Approximately 55% of our estimated proved reserves at December 31, 2013 and 26% of our production during 2013 were associated with our Appalachian properties.
	Cash and Cash Equivalents
	A substantial portion of our cash balances are not federally insured.

ACQUISITIONS_AND_DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
ACQUISITIONS AND DIVESTITURES	'
	NOTE 5 — ACQUISITIONS AND DIVESTITURES:
	Acquisitions
	In December 2012, we closed on the acquisition of an office building. The acquisition was accounted for according to the guidance provided in ASC 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value. Differences between the net fair value of net assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain. The building and land were recorded at fair value of $8,539. Consideration transferred in the transaction was $8,539 in cash, resulting in no goodwill or bargain purchase gain.
	On June 18, 2012, we completed the acquisition of a 25% working interest in the five block deep water Pompano field in Mississippi Canyon, an approximate 14% working interest in Mississippi Canyon Block 29 and a 10% working interest in certain aliquots of Mississippi Canyon Block 72. The acquisition was also accounted for according to the guidance provided in ASC 805, Business Combinations. Consideration transferred in the transaction was $26,398 in cash, resulting in no goodwill or bargain purchase gain. The following represents the allocation of the recorded value of net assets acquired in the transaction:
	Proved oil and gas properties	$	39,221
	Unevaluated oil and gas properties		1,637
	Asset retirement obligations		(14,460	)
	Total fair value of net assets	$	26,398
	Divestitures
	In October 2013, we completed the sale of our interest in the Weeks Island field for cash consideration of approximately $42,957 and the assumption of the associated asset retirement obligation of approximately $9,245. The sale was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

INVESTMENT_IN_OIL_AND_GAS_PROP

INVESTMENT IN OIL AND GAS PROPERTIES - UNAUDITED	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
INVESTMENT IN OIL AND GAS PROPERTIES - UNAUDITED	'
	NOTE 6 — INVESTMENT IN OIL AND GAS PROPERTIES — UNAUDITED:
	The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore in the continental United States:
			Year Ended December 31,
			2013			2012			2011
	Oil and gas properties – United States, proved and unevaluated:
	Balance, beginning of year		$	7,692,261		$	7,049,777		$	6,202,758
	Costs incurred during the year (capitalized):
	Acquisition costs, net of sales of unevaluated properties			70,903			102,807			270,354
	Exploratory costs			297,113			81,458			84,199
	Development costs (1)			378,242			395,555			426,355
	Salaries, general and administrative costs			32,815			25,318			24,430
	Interest			46,860			37,656			42,033
	Less: overhead reimbursements			(321	)		(310	)		(352	)
	Total costs incurred during the year, net of divestitures			825,612			642,484			847,019
	Balance, end of year		$	8,517,873		$	7,692,261		$	7,049,777
	Accumulated DD&A:
	Balance, beginning of year		($	5,510,166	)	($	5,174,729	)	($	4,804,949	)
	Provision for DD&A			(346,827	)		(341,096	)		(276,480	)
	Sale of proved properties			(51,767	)		5,659			(93,300	)
	Balance, end of year		($	5,908,760	)	($	5,510,166	)	($	5,174,729	)
	Net capitalized costs – United States, proved and unevaluated		$	2,609,113		$	2,182,095		$	1,875,048
	DD&A per Mcfe		$	3.43		$	3.69		$	3.45
	-1	Includes capitalized asset retirement costs of $54,737, $95,293 and $96,386, respectively.
	Costs incurred during the year (expensed):
	Lease operating expenses		$	201,153		$	215,003		$	175,881
	Transportation, processing and gathering expenses			42,172			21,782			8,958
	Production taxes			15,029			10,015			9,380
	Accretion expense			33,575			33,331			30,764
	Expensed costs – United States		$	291,929		$	280,131		$	224,983
	The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the years indicated:
			Year Ended December 31,
			2013			2012			2011
	Unevaluated oil and gas properties – United States:
	Net costs incurred (evaluated) during year:
	Acquisition costs		$	30,271		$	9,739			($2,397	)
	Exploration costs			188,830			(1,209	)		(51,207	)
	Capitalized interest			46,860			37,656			42,033
			$	265,961		$	46,186			($11,571	)
	During 2013, we entered into an agreement to participate in the drilling of exploratory wells in Canada. The following table discloses certain financial data relative to our oil and gas producing activities located in Canada:
			Year Ended
			December 31,
			2013
	Oil and gas properties – Canada, unevaluated:
	Balance, beginning of year		$	—
	Costs incurred during the year (capitalized):
	Acquisition costs			8,764
	Exploratory costs			1,819
	Total costs incurred during the year			10,583
	Balance, end of year, unevaluated		$	10,583
	The following table discloses financial data associated with unevaluated costs (United States and Canada) at December 31, 2013:
			Balance as of			Net Costs Incurred During the
			December 31,			Year Ended December 31,
			2013			2013			2012			2011		2010
														and prior
	Acquisition costs		$	306,793		$	78,555		$	29,959		$	41,442	$	156,837
	Exploration costs			305,422			248,846			56,033			499		44
	Capitalized interest			112,124			39,846			32,755			20,501		19,022
	Total unevaluated costs		$	724,339		$	367,247		$	118,747		$	62,442	$	175,903
	Approximately 140 specifically identified drilling projects are included in unevaluated costs at December 31, 2013 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2013, 2012 and 2011 totaled $46,860, $37,656 and $42,033, respectively.

DERIVATIVE_INSTRUMENTS_AND_HED

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	'
	NOTE 7 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
	Our hedging strategy is designed to protect our near and intermediate term cash flows from future declines in oil and natural gas prices. This protection is essential to capital budget planning, which is sensitive to expenditures that must be committed to in advance, such as rig contracts and the purchase of tubular goods. We enter into hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. These hedges are designated as cash flow hedges upon entering into the contract. We do not enter into hedging transactions for trading purposes. We have no fair value hedges.
	The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operations. Instruments not qualifying for hedge accounting treatment are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income). Monthly settlements of ineffective hedges are recognized in earnings through derivative expense (income) and cash flows from operations. Typically, a small portion of our derivative contracts are determined to be ineffective. This is because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract.
	We have entered into fixed-price swaps with various counterparties for a portion of our expected 2014, 2015 and 2016 oil and natural gas production from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate crude oil during the entire calendar month, and some are based on the average of the Intercontinental Exchange closing price for Brent crude oil during the entire calendar month. Our fixed-price gas swap settlements are based on the NYMEX price for the last day of a respective contract month. Swaps typically provide for monthly payments by us if prices rise above the swap price or monthly payments to us if prices fall below the swap price. Our fixed-price swap contracts are with The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America, Natixis and Regions Bank.
	All of our derivative instruments at December 31, 2013, 2012 and 2011 were designated as effective cash flow hedges. However, during the years ended December 31, 2013, 2012 and 2011, certain of our derivative contracts were determined to be partially ineffective. The following tables disclose the location and fair value amounts of derivative instruments reported in our balance sheet at December 31, 2013 and December 31, 2012.
	Fair Value of Derivative Instruments at December 31, 2013
			Asset Derivatives						Liability Derivatives
	Description		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of hedging contracts		$	4,549			Current liabilities: Fair value of hedging contracts		$	7,753
			Long-term assets: Fair value of hedging contracts			1,378			Long-term liabilities: Fair value of hedging contracts			470
					$	5,927					$	8,223
	Fair Value of Derivative Instruments at December 31, 2012
			Asset Derivatives						Liability Derivatives
	Description		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of hedging contracts		$	39,655			Current liabilities: Fair value of hedging contracts		$	149
			Long-term assets: Fair value of hedging contracts			9,199			Long-term liabilities: Fair value of hedging contracts			1,530
					$	48,854					$	1,679
	The following table discloses the before tax effect of derivative instruments in the statement of income for the years ended December 31, 2013, 2012 and 2011.
	Effect of Derivative Instruments on the Statement of Income for the Years Ended December 31, 2013, 2012 and 2011
	Derivatives in Cash		Amount of Gain				Gain (Loss) Reclassified from						Gain (Loss) Recognized in Income
	Flow Hedging		(Loss) Recognized				Accumulated Other Comprehensive Income						on Derivatives
	Relationships		in Other				into Income						(Ineffective Portion)
			Comprehensive				(Effective Portion) (a)
			Income on
			Derivatives
							Location						Location
			2013						2013					2013
	Commodity contracts			($26,945	)		Operating revenue—oil/gas production		$	20,289			Derivative expense, net		($2,090	)
	Total			($26,945	)				$	20,289					($2,090	)
			2012						2012					2012
	Commodity contracts		$	41,209			Operating revenue—oil/gas production		$	30,326			Derivative income, net	$	3,428
	Total		$	41,209					$	30,326				$	3,428
			2011						2011					2011
	Commodity contracts		$	43,089			Operating revenue—oil/gas production			($13,274	)		Derivative income, net	$	1,418
	Total		$	43,089						($13,274	)			$	1,418
	(a)	For the year ended December 31, 2013, effective hedging contracts increased oil revenue by $3,520 and increased gas revenue by $16,769. For the year ended December 31, 2012, effective hedging contracts increased oil revenue by $8,546 and increased gas revenue by $21,780. For the year ended December 31, 2011, effective hedging contracts decreased oil revenue by $32,706 and increased gas revenue by $19,432.
	At December 31, 2013, we had an accumulated other comprehensive loss of $1,395, net of tax, which related to the fair value of our swap contracts that were outstanding as of December 31, 2013, the majority of which will be reclassified into earnings in the next 12 months.
	Our derivative contracts are subject to netting arrangements. It is our policy not to offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. The following presents the potential impact of the rights of offset associated with our recognized assets and liabilities at December 31, 2013:
			As Presented				Effects of				With Effects
			Without				Netting				of Netting
			Netting
	Current assets: Fair value of hedging contracts		$	4,549			($	4,043	)		$	506
	Long-term assets: Fair value of hedging contracts			1,378				(274	)			1,104
	Current liabilities: Fair value of hedging contracts			(7,753	)			4,043				(3,710	)
	Long-term liabilities: Fair value of hedging contracts			(470	)			274				(196	)
	The following table illustrates our hedging positions for calendar years 2014, 2015 and 2016 as of February 25, 2014:
			Fixed-Price Swaps
			NYMEX (except where noted)
			Natural Gas								Oil
			Daily Volume				Swap				Daily Volume			Swap
			(MMBtus/d)				Price ($)				(Bbls/d)			Price ($)
	2014			10,000				4				1,000			90.06
	2014			10,000				4.04				1,000			92.25
	2014			10,000				4.105				1,000			93.55
	2014			10,000				4.19				1,000			94
	2014			10,000	(a)			4.25				1,000			98
	2014			10,000				4.25				1,000			98.3
	2014			10,000				4.35				2,000	(b)		98.85
	2014											1,000			99.65
	2014											1,000	(c)		103.3
	2015			10,000				4.005				1,000			89
	2015			10,000				4.12				1,000			90
	2015			10,000				4.15
2015			10,000				4.165
2015			10,000				4.22
2015			10,000				4.255
2016			10,000				4.11
2016			10,000				4.12
(a)	February through December
(b)	January through June
(c)	Brent crude oil contract

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
FAIR VALUE MEASUREMENTS	'
	NOTE 8 – FAIR VALUE MEASUREMENTS:
	U.S. GAAP establishes a fair value hierarchy that has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.
	As of December 31, 2013 and December 31, 2012, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for our credit risk and the credit risk of our counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy. For a more detailed description of our derivative instruments, see Note 7 - Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in marketable securities, which are included within the Level 1 fair value hierarchy.
	The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013:
		Fair Value Measurements at December 31, 2013
	Assets	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Assets		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Marketable securities	$	8,248	$	8,248	$	—	$	—
	Hedging contracts		5,927		—		5,927		—
	Total	$	14,175	$	8,248	$	5,927	$	—
		Fair Value Measurements at December 31, 2013
	Liabilities	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Liabilities		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Hedging contracts	$	8,223	$	—	$	8,223	$	—
	Total	$	8,223	$	—	$	8,223	$	—
	The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012:
		Fair Value Measurements at December 31, 2012
	Assets	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Assets		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Marketable securities	$	13,492	$	13,492	$	—	$	—
	Hedging contracts		48,854		—		48,854		—
	Total	$	62,346	$	13,492	$	48,854	$	—
		Fair Value Measurements at December 31, 2012
	Liabilities	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Liabilities		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Hedging contracts	$	1,679	$	—	$	1,679	$	—
	Total	$	1,679	$	—	$	1,679	$	—
	The fair value of cash and cash equivalents and our variable-rate bank debt approximated book value at December 31, 2013 and 2012. As of December 31, 2012, the fair value of the 8 5⁄8% Senior Notes due 2017 (the “2017 Notes”) was approximately $401,250. On December 13, 2013, our 2017 Notes were fully redeemed. As of December 31, 2013 and 2012, the fair value of the liability component of the 2017 Convertible Notes was approximately $260,377 and $249,601, respectively. On November 27, 2013, we completed the public offering of $475,000 aggregate principal amount of additional 7 1⁄2% Senior Notes due 2022 (the “2022 Notes”). See Note 11 – Long-Term Debt. As of December 31, 2013 and 2012, the fair value of the 2022 Notes was approximately $814,719 and $314,250, respectively.
	The fair value of the 2017 Notes and the fair value of the 2022 Notes were determined based upon quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (see Note 11 – Long-Term Debt) at inception, at December 31, 2013 and at December 31, 2012. The fair value of the liability was estimated using an income approach. The significant inputs in these determinations were market interest rates based on quotes obtained from brokers and represent Level 2 inputs.

ASSET_RETIREMENT_OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
ASSET RETIREMENT OBLIGATIONS	'
	NOTE 9 — ASSET RETIREMENT OBLIGATIONS:
	The change in our asset retirement obligations during the years ended December 31, 2013, 2012 and 2011 is set forth below:
		Year Ended December 31,
		2013			2012			2011
	Asset retirement obligations as of the beginning of the year, including current portion	$	488,302		$	425,779		$	373,920
	Liabilities incurred		19,043			3,869			7,993
	Liabilities settled		(79,695	)		(67,641	)		(63,226	)
	Liabilities assumed		—			15,263			59,441
	Divestment of properties		(9,245	)		(7,563	)		(10,900	)
	Accretion expense		33,575			33,331			30,764
	Revision of estimates		50,533			85,264			27,787
	Asset retirement obligations as of the end of the year, including current portion	$	502,513		$	488,302		$	425,779

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
INCOME TAXES	'
	NOTE 10 — INCOME TAXES:
	An analysis of our deferred taxes follows:
		As of December 31,
		2013			2012
	Tax effect of temporary differences:
	Net operating loss carryforwards	$	24,437		$	—
	Oil and gas properties – full cost		(576,393	)		(465,862	)
	Asset retirement obligations		180,905			175,788
	Stock compensation		5,537			5,588
	Hedges		826			(16,983	)
	Accrued incentive compensation		9,189			4,762
	Other		(3,484	)		1,391
			($358,983	)		($295,316	)
	We estimate that we have approximately ($10,904), $15,022 and ($20,386) of current federal income tax expense (benefit) for the years ended December 31, 2013, 2012 and 2011, respectively. We have a $7,366 and $10,027 current income tax receivable at December 31, 2013 and 2012, respectively.
	For tax reporting purposes, operating loss carryforwards totaled approximately $67,882 at December 31, 2013. If not utilized, such carryforwards would completely expire by the year 2033. In addition, we had approximately $1,453 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized.
	A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:
		Year Ended December 31,
		2013			2012			2011
	Income tax expense computed at the statutory federal income tax rate		35	%		35	%		35	%
	State taxes		1			1			1
	IRC Sec. 162(m) limitation		0.8			0.6			0.3
	Other		0.1			(0.5	)		(0.3	)
	Effective income tax rate		36.9	%		36.1	%		36	%
	Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to ($17,003), $3,918 and $20,290 for the years ended December 31, 2013, 2012 and 2011, respectively.
	As of December 31, 2013 and 2012, we had unrecognized tax benefits of $0 and $385, respectively. A reconciliation of the total amounts of unrecognized tax benefits follows:
	Total unrecognized tax benefits as of December 31, 2012	$	385
	Increases (decreases) in unrecognized tax benefits as a result of:		—
	Tax positions taken during a prior period		—
	Tax positions taken during the current period		—
	Settlements with taxing authorities		(385	)
	Lapse of applicable statute of limitations		—
	Total unrecognized tax benefits as of December 31, 2013	$	—
	Our unrecognized tax benefits pertained to proposed state income tax audit adjustments which were settled during 2013. See Note 15 – Commitments and Contingencies for additional information. It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.
	The tax years 2010 through 2012 remain subject to examination by major tax jurisdictions.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
LONG-TERM DEBT	'
	NOTE 11 — LONG-TERM DEBT:
	Long-term debt consisted of the following:
			As of December 31,
			2013		2012
	8 5⁄8% Senior Notes due 2017		$	—	$	375,000
	1 3⁄4% Senior Convertible Notes due 2017			252,084		239,126
	7 1⁄2% Senior Notes due 2022			775,000		300,000
	Bank debt			—		—
	Total long-term debt		$	1,027,084	$	914,126
	Bank Debt
	On April 26, 2011, we entered into an amended and restated revolving credit facility with commitments totaling $700,000 (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. Our bank credit facility matures on April 26, 2015. On December 18, 2013, our borrowing base was reaffirmed at $400,000. As of December 31, 2013 and February 25, 2014, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $21,406 had been issued pursuant to our bank credit facility, leaving $378,594 of availability under our bank credit facility.
	The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders, taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. If a reduction in our borrowing base were to fall below any outstanding balances under the bank credit facility plus any outstanding letters of credit, our agreement with the banks allows us one or more of three options to cure the borrowing base deficiency: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within 30 days after our written election to do so or (3) arrange to pay the deficiency in five equal monthly installments.
	Our bank credit facility is guaranteed by our only significant subsidiary, Stone Offshore. Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and natural gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and natural gas reserves reviewed in determining the borrowing base. At Stone’s option, loans under our bank credit facility will bear interest at a rate based on the adjusted London Interbank Offering (“Libor”) Rate plus an applicable margin, or a rate based on the prime rate or federal funds rate plus an applicable margin.
	Under the financial covenants of our bank credit facility, we must (1) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (2) maintain a ratio of consolidated EBITDA to consolidated Net Interest Expense, as defined in the credit agreement, for the preceding four quarterly periods of not less than 3.0 to 1. As of December 31, 2013, our debt to EBITDA ratio was 1.73 to 1 and our EBITDA to consolidated Net Interest Expense ratio was approximately 18.40 to 1. In addition, our bank credit facility includes certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases. These covenants also restrict our ability to prepay other indebtedness under certain circumstances. We were in compliance with all covenants as of December 31, 2013.
	2017 Convertible Notes
	On March 6, 2012, we issued in a private offering $300,000 in aggregate principal amount of the 2017 Convertible Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”). The 2017 Convertible Notes are convertible into cash, shares of our common stock or a combination of cash and shares of our common stock, at our election, based on an initial conversion rate of 23.4449 shares of our common stock per $1 principal amount of 2017 Convertible Notes, which corresponds to an initial conversion price of approximately $42.65 per share of our common stock. On December 31, 2013, our closing share price was $34.59. The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture related to the 2017 Convertible Notes.
	The 2017 Convertible Notes may be converted by the holder, in multiples of $1 principal amount, only under the following circumstances:
		•		prior to December 1, 2016, on any date during any calendar quarter beginning after June 30, 2012 (and only during such calendar quarter) if the closing sale price of our common stock was more than 130% of the then current conversion price for at least 20 trading days in the period of the 30 consecutive trading days ending on the last trading day of the previous calendar quarter;
		•		prior to December 1, 2016, if we distribute to all or substantially all holders of our common stock rights, options or warrants entitling them to purchase, for a period of 45 calendar days or less from the declaration date for such distribution, shares of our common stock at a price per share less than the average closing sale price of our common stock for the 10 consecutive trading days immediately preceding, but excluding, the declaration date for such distribution;
		•		prior to December 1, 2016, if we distribute to all or substantially all holders of our common stock cash, other assets, securities or rights to purchase our securities, which distribution has a per share value exceeding 10% of the closing sale price of our common stock on the trading day immediately preceding the declaration date for such distribution, or if we engage in certain corporate transactions described in the indenture related to the 2017 Convertible Notes;
		•		prior to December 1, 2016, during the five consecutive business-day period following any five consecutive trading-day period in which the trading price per $1 principal amount of 2017 Convertible Notes for each trading day during such five trading-day period was less than 98% of the closing sale price of our common stock for each trading day during such five trading-day period multiplied by the then current conversion rate; or
		•		on or after December 1, 2016, and prior to the close of business on the second scheduled trading day immediately preceding the maturity date of the 2017 Convertible Notes, which is March 1, 2017, without regard to the foregoing conditions.
	Upon conversion, we will be obligated to pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock, at our election. If we satisfy our conversion obligation solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of our common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture related to the 2017 Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture related to the 2017 Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 2017 Convertible Notes will not receive any cash payment representing accrued and unpaid interest. Instead, interest will be deemed to be paid by the cash, shares of our common stock or a combination of cash and shares of our common stock paid or delivered, as the case may be, upon conversion of a 2017 Convertible Note.
	In connection with the offering, we entered into convertible note hedge transactions with respect to our common stock (the “Purchased Call Options”) with Barclays Capital Inc., acting as agent for Barclays Bank PLC and Bank of America, N.A. (the “Dealers”). We paid an aggregate amount of approximately $70,830 to the Dealers for the Purchased Call Options. The Purchased Call Options cover, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock at a strike price that corresponds to the initial conversion price of the 2017 Convertible Notes, also subject to adjustment, and are exercisable upon conversion of the 2017 Convertible Notes.
	We also entered into separate warrant transactions whereby, in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act, we sold to the Dealers warrants to acquire, subject to customary antidilution adjustments, approximately 7,033,470 shares of our common stock (the “Sold Warrants”) at a strike price of $55.91 per share of our common stock. We received aggregate proceeds of approximately $40,170 from the sale of the Sold Warrants to the Dealers. If, upon expiration of the Sold Warrants, the price per share of our common stock, as measured under the Sold Warrants, is greater than the strike price of the Sold Warrants, we will be required to issue, without further consideration, under each Sold Warrant a number of shares of our common stock with a value equal to the amount of such difference.
	As of December 31, 2013, the carrying amount of the liability component of the 2017 Convertible Notes was $252,084 and $1,750 had been accrued in connection with the March 1, 2014 interest payment. During the year ended December 31, 2013, we recognized $12,959 of interest expense for the amortization of the discount and $1,238 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the year ended December 31, 2012, we recognized $9,956 of interest expense for the amortization of the discount and $951 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. During the years ended December 31, 2013 and 2012, we recognized $5,250 and $4,302, respectively, of interest expense related to the contractual interest coupon on the 2017 Convertible Notes.
	2022 Notes
	On November 8, 2012, we completed the public offering of $300,000 aggregate principal amount of our 2022 Notes, which are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $293,203. On November 27, 2013, we completed the public offering of an additional $475,000 aggregate principal amount of our 2022 Notes at a 3% premium. The net proceeds from this offering after deducting underwriting discounts, commissions, fees and expenses totaled $480,195. The 2022 Notes rank equally in right of payment with all of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt. The 2022 Notes mature on November 15, 2022, and interest is payable on the 2022 Notes on each May 15 and November 15. We may redeem some or all of the 2022 Notes at any time on or after November 15, 2017 at the redemption prices specified in the indenture, and we may redeem some or all of the 2022 Notes prior to November 15, 2017 at a make-whole redemption price as specified in the indenture. We also may redeem up to 35% of the 2022 Notes prior to November 15, 2015 with cash proceeds from certain equity offerings at a redemption price of 107.500% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness, or we experience certain changes of control, each as described in the indenture, we must offer to repurchase the 2022 Notes. The 2022 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2022 Notes a right to accelerate payment. At December 31, 2013, $7,266 had been accrued in connection with the May 15, 2014 interest payment.
	2017 Notes
	On January 26, 2010, we issued $275,000 aggregate principal amount of our 2017 Notes. On November 17, 2010, we completed a public offering of an additional $100,000 aggregate principal amount of our 2017 Notes. In November 2013, we used proceeds from the 2022 Notes offering to purchase a portion of our 2017 Notes pursuant to a tender offer and consent solicitation. In December 2013, the remaining 2017 Notes were redeemed in full. The total cost of the redemption was $406,967, which included $396,014 to redeem the notes plus accrued and unpaid interest of $10,953. The transaction resulted in a charge to earnings of $27,279 in the fourth quarter of 2013, which represented the premium paid for the repurchase and redemption of $21,014 and the write off of the remaining deferred financing costs related to the 2017 Notes of $6,265.
	Deferred Financing Cost and Interest Cost
	Other assets at December 31, 2013 and 2012 included approximately $11,754 and $27,753, respectively, of deferred financing costs, net of accumulated amortization. These costs related primarily to the issuance of the 2017 Convertible Notes, the 2022 Notes and our bank credit facility. The costs associated with the 2017 Convertible Notes are being amortized over the life of the notes using a method that applies an effective interest rate of 7.51%. The costs associated with the November 2012 issuance and November 2013 issuance of the 2022 Notes are being amortized over the life of the notes using a method that applies effective interest rates of 7.75% and 7.04%, respectively. The costs associated with our bank credit facility are being amortized over the term of our bank credit facility.
	Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2013, 2012 and 2011 was $79,697, $68,031 and $51,322 respectively.

ACCUMULATED_OTHER_COMPREHENSIV

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	'
	NOTE 12 — ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
	Changes in accumulated other comprehensive income (loss) by component for the year ended December 31, 2013 were as follows:
		Cash			Foreign			Total
		Flow			Currency
		Hedges			Items
	For the Year Ended December 31, 2013
	Beginning balance, net of tax	$	28,833		$	—		$	28,833
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		(26,945	)		—			(26,945	)
	Foreign currency translations		—			(667	)		(667	)
	Income tax effect		9,701			—			9,701
	Net of tax		(17,244	)		(667	)		(17,911	)
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		20,289			—			20,289
	Income tax effect		(7,305	)		—			(7,305	)
	Net of tax		12,984			—			12,984
	Other comprehensive income (loss), net of tax		(30,228	)		(667	)		(30,895	)
	Ending balance, net of tax		($1,395	)		($667	)		($2,062	)
	In 2012 and 2011, the only component of accumulated other comprehensive income (loss) related to our cash flow hedges. Changes in accumulated other comprehensive income (loss) for the years ended December 31, 2012 and 2011 were as follows:
		Cash Flow
		Hedges
	For the Year Ended December 31, 2012
	Beginning balance, net of tax	$	21,868
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		41,209
	Income tax effect		(14,836	)
	Net of tax		26,373
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		30,326
	Income tax effect		(10,918	)
	Net of tax		19,408
	Other comprehensive income, net of tax		6,965
	Ending balance, net of tax	$	28,833
		Cash Flow
		Hedges
	For the Year Ended December 31, 2011
	Beginning balance, net of tax		($14,204	)
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		43,089
	Income tax effect		(15,512	)
	Net of tax		27,577
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		(13,274	)
	Income tax effect		4,779
	Net of tax		(8,495	)
	Other comprehensive income, net of tax		36,072
	Ending balance, net of tax	$	21,868

SHAREBASED_COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
SHARE-BASED COMPENSATION	'
	NOTE 13 — SHARE-BASED COMPENSATION:
	Under the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (the “2009 Plan”), we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of our common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire 10 years subsequent to award. In addition, the 2009 Plan provides that shares available under the 2009 Plan may be granted as restricted stock. Restricted stock typically vests over a one- to three-year period.
	We record share-based compensation expense under U.S. GAAP for equity-based compensation awards based on the fair value on the date of grant. Compensation expense for equity-based compensation awards is recognized in our financial statements over the vesting period of the award.
	For the year ended December 31, 2013, we incurred $15,425 of share-based compensation, of which $15,405 related to restricted stock issuances and $20 related to stock option grants, and of which a total of approximately $5,078 was capitalized into oil and gas properties. For the year ended December 31, 2012, we incurred $13,399 of share-based compensation, of which $13,308 related to restricted stock issuances and $91 related to stock option grants, and of which a total of approximately $4,288 was capitalized into oil and gas properties. For the year ended December 31, 2011, we incurred $8,914 of share-based compensation, of which $8,796 related to restricted stock issuances and $118 related to stock option grants, and of which a total of approximately $3,010 was capitalized into oil and gas properties. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.
	Stock Options. There were no stock option grants during the years ended December 31, 2013, 2012 or 2011.
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2013 is as follows (amounts in table represent actual values except where indicated otherwise):
		Number			Wgtd.		Wgtd.		Aggregate
		of			Avg.		Avg.		Intrinsic
		Options			Exercise		Term		Value
					Price				(in thousands)
	Options outstanding, beginning of period		411,794		$	39.04
	Granted		—			—
	Exercised		—			—
	Forfeited		(15,250	)		42.45
	Expired		(65,370	)		36.56
	Options outstanding, end of period		331,174			39.37	2.2 years		$	1,708
	Options exercisable, end of period		318,279			40.62	2.1 years			1,373
	Options unvested, end of period		12,895			8.64	5.0 years			335
	Exercise prices for stock options outstanding at December 31, 2013 range from $6.97 to $53.20.
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2012 is as follows (amounts in table represent actual values except where indicated otherwise):
		Number			Wgtd.		Wgtd.		Aggregate
		of			Avg.		Avg.		Intrinsic
		Options			Exercise		Term		Value
					Price				(in thousands)
	Options outstanding, beginning of period		438,394		$	38.76
	Granted		—			—
	Exercised		—			—
	Forfeited		(4,200	)		35.54
	Expired		(22,400	)		34.25
	Options outstanding, end of period		411,794			39.04	2.8 years		$	766
	Options exercisable, end of period		378,004			41	2.5 years			459
	Options unvested, end of period		33,790			17.17	5.4 years			307
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2011 is as follows (amounts in table represent actual values except where indicated otherwise):
		Number			Wgtd.		Wgtd.		Aggregate
		of			Avg.		Avg.		Intrinsic
		Options			Exercise		Term		Value
					Price				(in thousands)
	Options outstanding, beginning of period		484,694		$	39.43
	Granted		—			—
	Exercised		—			—
	Forfeited		(13,300	)		37.98
	Expired		(33,000	)		48.85
	Options outstanding, end of period		438,394			38.76	3.6 years		$	1,143
	Options exercisable, end of period		378,710			41.66	3.1 years			457
	Options unvested, end of period		59,684			20.36	6.1 years			686
	Restricted Stock. The fair value of restricted shares is typically determined based on the average of our high and low stock prices on the grant date. During the year ended December 31, 2013, we issued 848,498 shares of restricted stock valued at $17,487. During the year ended December 31, 2012, we issued 670,818 shares of restricted stock valued at $21,085. During the year ended December 31, 2011, we issued 597,062 shares of restricted stock valued at $14,100.
	A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2013, 2012 and 2011 is as follows (amounts in table represent actual values):
		2013					2012						2011
		Number of			Wgtd.		Number of				Wgtd.		Number			Wgtd.
		Restricted			Avg.		Restricted				Avg.		of			Avg.
		Shares			Fair Value		Shares				Fair Value		Restricted			Fair Value
					Per Share						Per Share		Shares			Per Share
	Restricted stock outstanding, beginning of period		1,108,874		$	27.56		923,740			$	20.08		783,606		$	17.24
	Issuances		848,498			20.61		670,818				31.43		597,062			23.62
	Lapse of restrictions		(534,041	)		25.45		(462,141	)			18.29		(419,543	)		19.91
	Forfeitures		(165,278	)		26.43		(23,543	)			26.1		(37,385	)		18.92
	Restricted stock outstanding, end of period		1,258,053		$	23.92		1,108,874			$	27.56		923,740		$	20.08
	As of December 31, 2013, there was $17,004 of unrecognized compensation cost related to all non-vested share-based compensation arrangements under the 2009 Plan. That cost is being amortized on a straight-line basis over the vesting period and is expected to be recognized over a weighted-average period of 1.7 years.
	Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital or an increase in income tax expense depending on the pool of available excess tax benefits to offset such deficit. Adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting were ($884), $814 and $735 in 2013, 2012 and 2011, respectively.

SHARE_REPURCHASE_PROGRAM

SHARE REPURCHASE PROGRAM	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
SHARE REPURCHASE PROGRAM	'
	NOTE 14 — SHARE REPURCHASE PROGRAM:
	On September 24, 2007, our board of directors authorized a share repurchase program for an aggregate amount of up to $100,000. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions and may be suspended or discontinued at any time. Through December 31, 2013, 300,000 shares had been repurchased under this program at a total cost of $7,071, or an average price of $23.57 per share. No shares were repurchased during the years ended December 31, 2013, 2012 and 2011.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	NOTE 15 — COMMITMENTS AND CONTINGENCIES:
	Leases
	We lease office facilities in Lafayette and New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia under the terms of long-term, non-cancelable leases expiring on various dates through 2018. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net annual commitments under all leases, subleases and contracts with non-cancelable terms in excess of 12 months at December 31, 2013 were as follows:
	2014	$	736
	2015		637
	2016		358
	2017		301
	2018		147
	Payments related to our lease obligations for the years ended December 31, 2013, 2012 and 2011 were approximately $597, $894 and $446, respectively.
	Other Commitments
	We are contingently liable to surety insurance companies in the amount of $81,878 relative to bonds issued on our behalf to the Bureau of Ocean Energy Management (the “BOEM”), federal and state agencies and certain third parties from which we purchased oil and gas working interests. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.
	In connection with our exploration and development efforts, we are contractually committed to the use of drilling rigs and the acquisition of seismic data in the aggregate amount of $216,726 to be incurred over the next four years. We have placed $22,350 on deposit to guarantee these obligations.
	The Oil Pollution Act (the “OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA and a final rule adopted by the BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in Outer Continental Shelf (the “OCS”) waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s final rule. We do not anticipate that we will experience any difficulty in continuing to satisfy the BOEM’s requirements for demonstrating financial responsibility under the OPA and the BOEM’s regulations.
	Litigation
	We are named as a defendant in certain lawsuits and are a party to certain regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.
	Since 2003, we have been involved in disputes with the Louisiana Department of Revenue (the “LDR”), which resulted in several petitions being filed by the LDR in Louisiana state court, claiming additional franchise taxes due. In addition, we received preliminary assessments from the LDR of additional franchise and income taxes resulting from audits of Stone and its subsidiaries. These petitions and assessments primarily related to the LDR’s assertion that sales of crude oil and natural gas from properties located on the OCS that are transported through the state should be sourced to the state for purposes of computing the Louisiana franchise tax and income tax apportionment ratios. By agreement dated November 22, 2013, Stone executed a settlement with the state in the amount of $13,000, resolving all claims asserted in litigation, as well as assessments proposed by the LDR for franchise and income taxes alleged to be due by Stone for the tax years 1999 through 2009, including claims for interest thereon. The agreement was reached under an amnesty program pursuant to Act 421 of the 2013 Regular Session of the Louisiana Legislature. The settlement amount, less income tax and interest amounts previously accrued, has been recorded as an expense in the accompanying consolidated statement of income. The tax years 2011 through 2013 remain subject to examination but the exposure to additional assessments is immaterial.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2013
Postemployment Benefits [Abstract]	'
EMPLOYEE BENEFIT PLANS	'
	NOTE 16 — EMPLOYEE BENEFIT PLANS:
	We have entered into deferred compensation and disability agreements with certain of our officers and former officers. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2013, the liability for such vested benefits was approximately $1,062 and is recorded in current and other long-term liabilities.
	The following is a brief description of each incentive compensation plan applicable to our employees:
	Annual Cash Incentive Compensation Plan
	The Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, provides for annual cash incentive bonuses that are tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. Stone incurred expenses of $15,340, $8,113, and $11,600, net of amounts capitalized, for each of the years ended December 31, 2013, 2012 and 2011, respectively, related to incentive compensation bonuses to be paid under the revised plan.
	Stock Incentive Plans
	At the 2011 Annual Meeting of Stockholders, the stockholders approved the First Amendment (the “First Amendment”) to the 2009 Plan. The First Amendment increases the number of shares of our common stock that Stone may issue under the 2009 Plan, and the number of shares of our common stock that may be issued under the 2009 Plan through incentive stock options by 2,800,000 shares, effective May 20, 2011. The 2009 Plan is an amendment and restatement of the company’s 2004 Amended and Restated Stock Incentive Plan (the “2004 Plan”), and it supersedes and replaces in its entirety the 2004 Plan. The 2009 Plan provides for the granting of incentive stock options and restricted stock awards or any combination as is best suited to the circumstances of the particular employee or nonemployee director. The 2009 Plan eliminates the automatic grant of stock options or restricted stock awards to nonemployee directors that was provided for in the 2004 Plan so that awards under the 2009 Plan are entirely at the discretion of our board of directors. Under the 2009 Plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of our common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire 10 years subsequent to award. In addition, the 2009 Plan provides that shares available under the 2009 Plan may be granted as restricted stock. Restricted stock grants typically vest in one to three years at the discretion of the Compensation Committee of our board of directors. At December 31, 2013, we had approximately 2,081,866 additional shares available for issuance pursuant to the Plan.
	401(k) and Deferred Compensation Plans
	The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the directions of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2013, 2012 and 2011, Stone contributed $1,793, $1,759 and $1,435, respectively, to the plan.
	The Stone Energy Corporation Deferred Compensation Plan provides eligible executives and employees with the option to defer up to 100% of their compensation for a calendar year and we may, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by our board of directors. To date there have been no matching contributions made by Stone. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2013 and 2012, plan assets of $8,248 and $7,498, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.
	Change of Control and Severance Plans
	On April 7, 2009, we amended and restated our Executive Change of Control and Severance Plan effective as of December 31, 2008 (as so amended and restated, the “Executive Plan”). The Executive Plan also replaced and superseded our Executive Change in Control and Severance Policy that was maintained for certain designated executives (specifically, the CEO and CFO). The Executive Plan will provide the company’s officers that are terminated in the event of a change of control and upon certain other terminations of employment with change of control and severance benefits as defined in the Executive Plan. Executives who are terminated within the scope of the Executive Plan will be entitled to certain payments and benefits including the following: a base salary up to the date of termination; in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of his annual pay and any target bonus at the one hundred percent level; a lump sum amount representing a pro rata share of the bonus opportunity up to the date of termination at the then projected rate of payout; in the case of officers other than the CEO and CFO and an involuntary termination occurring outside a change of control period, a lump sum severance payment in an amount equal to the executive’s annual base salary; in the case of officers other than the CEO and CFO and an involuntary termination occurring during a change of control period, a lump sum severance payment in an amount equal to 2.99 times the executive’s annual base salary; continued health plan coverage for six months and outplacement services. In the case of the CEO and CFO, if the payments would be “excess parachute payments,” they will be reduced as necessary to avoid the 20% excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”), but only if the executive is in a better net after-tax position after such reduction. Also, if a payment would be to a “key employee” for purposes of Section 409A of the Code, payment will be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated vesting and cash-out of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a pro-rated portion of the projected bonus, if any, for the year of change of control.
	On December 7, 2007, our board of directors approved and adopted the Stone Energy Corporation Employee Change of Control Severance Plan (“Employee Severance Plan”), as amended and restated to comply with the final regulations under Section 409A of the Internal Revenue Code and to provide that said plan will remain in force and effect unless and until terminated by our board of directors. The Employee Severance Plan amended and restated the company’s previous Employee Change of Control Severance Plan dated November 16, 2006. The Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the six-month period following a change of control, including a resignation by the employee relating to a change in duties. Employees who are terminated within the scope of the Employee Severance Plan will be entitled to certain payments and benefits including the following: a lump sum equal to (1) weekly pay times full years of service, plus (2) one week’s pay for each full $10,000 of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay; continued health plan coverage for six months; and a pro-rated portion of the employee’s targeted bonus for the year. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated vesting and cash-out of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a lump sum cash payment equal to the product of (i) the number of “restricted shares” of company stock that the employee would have received under the company’s stock plan but did not receive for the time-vested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (ii) the price per share of the company’s common stock utilized in effecting the change of control, provided that such amount shall be pro-rated by multiplying such amount by the number of full months that have elapsed from January 1 of that calendar year to the effective date of the change of control and then dividing the result by 12.

OIL_AND_GAS_RESERVE_INFORMATIO

OIL AND GAS RESERVE INFORMATION - UNAUDITED	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
OIL AND GAS RESERVE INFORMATION - UNAUDITED	'
	NOTE 17 — OIL AND GAS RESERVE INFORMATION – UNAUDITED:
	Our estimated net proved oil and natural gas reserves at December 31, 2013 have been prepared in accordance with guidelines established by the Securities and Exchange Commission (“SEC”). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.
	The following table sets forth an analysis of the estimated quantities of net proved and proved developed oil (including condensate), natural gas and natural gas liquids (“NGL”) reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil, natural gas and NGL reserves at December 31, 2013, 2012 and 2011 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption. In the first quarter of 2012, we began reporting NGL volumes and revenues separately from gas volumes. Historically, we reported “wet” gas volumes, which included entrained liquids. We now report NGLs and “dry” gas (shrunk for removal of liquids) volumes. Reserve volumes for the year ended December 31, 2011 have been reclassified to conform to the current presentation. Reserve volumes for the year ended December 31, 2010 have not been reclassified to conform to the current presentation given the immateriality of NGL volumes in such period.
		Oil			NGLs			Natural			Oil,
		(MBbls)			(MBbls)			Gas			Natural
								(MMcf)			Gas and
											NGLs
											(MMcfe)
	Estimated proved reserves as of December 31, 2010		33,203			—			274,705			473,923
	Revisions of previous estimates		2,889			4,911			(26,725	)		20,075
	Extensions, discoveries and other additions		3,544			—			93,520			114,784
	Purchase of producing properties		14,396			—			24,595			110,971
	Sale of reserves		(1,950	)		—			(2,150	)		(13,850	)
	Production		(6,427	)		(506	)		(38,466	)		(80,064	)
	Estimated proved reserves as of December 31, 2011		45,655			4,405			325,479			625,839
	Revisions of previous estimates		(1,559	)		9,349			(26,694	)		20,050
	Extensions, discoveries and other additions		3,681			4,856			131,408			182,633
	Purchase of producing properties		4,336			619			8,168			37,895
	Sale of reserves		(60	)		—			(418	)		(775	)
	Production		(7,135	)		(1,163	)		(42,569	)		(92,357	)
	Estimated proved reserves as of December 31, 2012		44,918			18,066			395,374			773,285
	Revisions of previous estimates		3,606			2,439			36,006			72,275
	Extensions, discoveries and other additions		2,367			4,395			79,729			120,299
	Sale of reserves		(170	)		—			(214	)		(1,235	)
	Production		(6,894	)		(1,603	)		(50,129	)		(101,111	)
	Estimated proved reserves as of December 31, 2013		43,827			23,297			460,766			863,513
	Estimated proved developed reserves:
	as of December 31, 2011		30,914			3,195			171,871			376,528
	as of December 31, 2012		29,005			8,593			210,956			436,540
	as of December 31, 2013		27,920			11,569			246,946			483,885
	The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.
	Year Ended December 31, 2013. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (117 Bcfe). Revisions of previous estimates were primarily the result of positive reserve report pricing changes extending the economic limits of reservoirs (17.8 Bcfe) and well performance (54.5 Bcfe).
	Year Ended December 31, 2012. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (162 Bcfe) and our deep gas development project at LaCantera (17 Bcfe). Purchase of producing properties relates to our acquisition of an additional interest in the Pompano field.
	Year Ended December 31, 2011. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (94 Bcfe), our deep gas development project at LaPosada (11 Bcfe) and our GOM drilling program at Mississippi Canyon Block 109 (6 Bcfe). Purchase of producing properties primarily relates to our acquisition of the Pompano and Mica fields (102 Bcfe) and our acquisition of an additional 15% working interest in the Pyrenees project (6 Bcfe). Sale of reserves primarily relates to the sale of our non-operated interest in the Main Pass Block 296 and 311 fields (13 Bcfe).
	The following tables present the standardized measure of discounted future net cash flows related to estimated proved oil, natural gas and NGL reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2013. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil, natural gas and NGL reserves. Prices are based on either the historical 12-month average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2013 average historical 12-month oil and gas prices, net of applicable differentials, were $102.21 per Bbl of oil, $37.59 per Bbl of NGLs and $3.66 per Mcf of gas. The 2012 average 12-month oil and gas prices, net of applicable differentials, were $101.20 per Bbl of oil, $38.23 per Bbl of NGLs and $2.68 per Mcf of gas. The 2011 average 12-month oil and gas prices, net of applicable differentials, were $100.97 per Bbl of oil, $58.26 per Bbl of NGLs and $4.74 per Mcf of gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
		Standardized Measure Year Ended December 31,
		2013			2012			2011
	Future cash inflows	$	7,040,928		$	6,295,455		$	6,171,279
	Future production costs		(2,062,657	)		(1,946,426	)		(1,747,806	)
	Future development costs		(1,431,101	)		(1,241,531	)		(1,219,214	)
	Future income taxes		(884,637	)		(799,007	)		(852,364	)
	Future net cash flows		2,662,533			2,308,491			2,351,895
	10% annual discount		(977,531	)		(794,632	)		(808,933	)
	Standardized measure of discounted future net cash flows	$	1,685,002		$	1,513,859		$	1,542,962
		Changes in Standardized Measure
		Year Ended December 31,
		2013			2012			2011
	Standardized measure at beginning of year	$	1,513,859		$	1,542,962		$	957,629
	Sales and transfers of oil, gas and NGLs produced, net of production costs		(708,017	)		(697,741	)		(670,347	)
	Changes in price, net of future production costs		229,425			(380,841	)		502,324
	Extensions and discoveries, net of future production and development costs		155,592			178,272			293,168
	Changes in estimated future development costs, net of development costs incurred during the period		28,684			212,329			97,852
	Revisions of quantity estimates		281,558			76,450			(27,854	)
	Accretion of discount		202,087			207,292			118,722
	Net change in income taxes		(28,084	)		22,947			(300,363	)
	Purchases of reserves in-place		—			276,389			567,286
	Sales of reserves in-place		15,531			2,480			(36,278	)
	Changes in production rates due to timing and other		(5,633	)		73,320			40,823
	Net increase (decrease) in standardized measure		171,143			(29,103	)		585,333
	Standardized measure at end of year	$	1,685,002		$	1,513,859		$	1,542,962

SUMMARIZED_QUARTERLY_FINANCIAL

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	'
	NOTE 18 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:
	The results of operations by quarter are as follows:
			2013 Quarter Ended
			March 31		June 30		September 30		December 31
	Operating revenue		$	233,732	$	245,877	$	256,685	$	239,253
	Income from operations			72,828		69,525		62,422		37,206	(a)
	Net income			40,758		39,022		36,102		1,752	(a) (b)
	Basic earnings per share		$	0.82	$	0.78	$	0.72	$	0.04
	Diluted earnings per share		$	0.82	$	0.78	$	0.72	$	0.04
			2012 Quarter Ended
			March 31		June 30		September 30		December 31
	Operating revenue		$	244,957	$	226,561	$	227,397	$	254,871
	Income from operations			84,927		56,156		44,485		78,397
	Net income			50,974		30,547		23,659		44,246
	Basic earnings per share		$	1.04	$	0.62	$	0.48	$	0.89
	Diluted earnings per share		$	1.04	$	0.62	$	0.48	$	0.89
	(a)	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
	(b)	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

SUBSEQUENT_EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
SUBSEQUENT EVENTS	'
	NOTE 19 — SUBSEQUENT EVENTS:
	On January 16, 2014, we completed the sale of our interests in the Cut Off and Clovelly fields for cash consideration of approximately $41,575. On January 31, 2014, we completed the sale of our interest in the Hatch Point field for cash consideration of approximately $9,720. These sales will be accounted for as an adjustment to capitalized costs with no gain or loss recognized.

GUARANTOR_FINANCIAL_STATEMENTS

GUARANTOR FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
GUARANTOR FINANCIAL STATEMENTS	'
	NOTE 20 – GUARANTOR FINANCIAL STATEMENTS:
	Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of the 2017 Convertible Notes and 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents consolidating financial information as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 on an issuer (parent company), Guarantor Subsidiary, Non-Guarantor Subsidiaries, and consolidated basis. Elimination entries presented are necessary to combine the entities.
	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-13
	(In thousands)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiary			Subsidiaries
	Assets
	Current assets:
	Cash and cash equivalents		$	246,294		$	84,290		$	640		$	—		$	331,224
	Accounts receivable			74,887			97,128			—			(44	)		171,971
	Fair value of hedging contracts			—			4,549			—			—			4,549
	Current income tax receivable			7,366			—			—			—			7,366
	Deferred taxes *			8,659			23,051			—			—			31,710
	Inventory			3,440			283			—			—			3,723
	Other current assets			1,874			—			—			—			1,874
	Total current assets			342,520			209,301			640			(44	)		552,417
	Oil and gas properties, full cost method:
	Proved			1,309,527			6,494,590			—			—			7,804,117
	Less: accumulated DD&A			(459,932	)		(5,448,828	)		—			—			(5,908,760	)
	Net proved oil and gas properties			849,595			1,045,762			—			—			1,895,357
	Unevaluated			325,113			388,643			10,583			—			724,339
	Other property and equipment, net			26,178			—			—			—			26,178
	Fair value of hedging contracts			—			1,378			—			—			1,378
	Other assets, net			45,410			1,349			2,128			—			48,887
	Investment in subsidiary			747,472			—			12,711			(760,183	)		—
	Total assets		$	2,336,288		$	1,646,433		$	26,062			($760,227	)	$	3,248,556
	Liabilities and Stockholders’ Equity
	Current liabilities:
	Accounts payable to vendors		$	173,147		$	22,530		$	44			($44	)	$	195,677
	Undistributed oil and gas proceeds			34,386			2,643			—			—			37,029
	Accrued interest			9,022			—			—			—			9,022
	Fair value of hedging contracts			—			7,753			—			—			7,753
	Asset retirement obligations			—			67,161			—			—			67,161
	Other current liabilities			53,682			838			—			—			54,520
	Total current liabilities			270,237			100,925			44			(44	)		371,162
	Long-term debt			1,027,084			—			—			—			1,027,084
	Deferred taxes *			10,227			380,466			—			—			390,693
	Asset retirement obligations			4,945			430,407			—			—			435,352
	Fair value of hedging contracts			—			470			—			—			470
	Other long-term liabilities			53,509			—			—			—			53,509
	Total liabilities			1,366,002			912,268			44			(44	)		2,278,270
	Commitments and contingencies Stockholders’ equity:
	Common stock			488			—			—			—			488
	Treasury stock			(860	)		—			—			—			(860	)
	Additional paid-in capital			1,397,885			1,309,563			27,403			(1,336,966	)		1,397,885
	Accumulated deficit			(425,165	)		(574,003	)		(52	)		574,055			(425,165	)
	Accumulated other comprehensive loss			(2,062	)		(1,395	)		(1,333	)		2,728			(2,062	)
	Total stockholders’ equity			970,286			734,165			26,018			(760,183	)		970,286
	Total liabilities and stockholders’ equity		$	2,336,288		$	1,646,433		$	26,062			($760,227	)	$	3,248,556
	*	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.
	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-12
	(In thousands)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiary			Subsidiaries
	Assets
	Current assets:
	Cash and cash equivalents		$	228,398		$	51,128		$	—		$	—		$	279,526
	Accounts receivable			59,213			108,075			—			—			167,288
	Fair value of hedging contracts			—			39,655			—			—			39,655
	Current income tax receivable			10,027			—			—			—			10,027
	Deferred taxes *			5,947			9,567			—			—			15,514
Inventory			3,924			283			—			—			4,207
Other current assets			3,626			—			—			—			3,626
Total current assets			311,135			208,708			—			—			519,843
Oil and gas properties, full cost method:
Proved			1,004,808			6,239,658			—			—			7,244,466
Less: accumulated DD&A			(370,111	)		(5,140,055	)		—			—			(5,510,166	)
Net proved oil and gas properties			634,697			1,099,603			—			—			1,734,300
Unevaluated			254,757			193,038			—			—			447,795
Other property and equipment, net			22,115			—			—			—			22,115
Fair value of hedging contracts			—			9,199			—			—			9,199
Other assets, net			41,679			1,500			—			—			43,179
Investment in subsidiary			736,331			—			—			(736,331	)		—
Total assets		$	2,000,714		$	1,512,048		$	—			($736,331	)	$	2,776,431
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		$	74,503		$	19,858		$	—		$	—		$	94,361
Undistributed oil and gas proceeds			21,841			1,573			—			—			23,414
Accrued interest			18,546			—			—			—			18,546
Fair value of hedging contracts			—			149			—			—			149
Asset retirement obligations			—			66,260			—			—			66,260
Other current liabilities			16,765			—			—			—			16,765
Total current liabilities			131,655			87,840			—			—			219,495
Long-term debt			914,126			—			—			—			914,126
Deferred taxes *			47,758			263,072			—			—			310,830
Asset retirement obligations			5,479			416,563			—			—			422,042
Fair value of hedging contracts			—			1,530			—			—			1,530
Other long-term liabilities			29,563			6,712			—			—			36,275
Total liabilities			1,128,581			775,717			—			—			1,904,298
Commitments and contingencies Stockholders’ equity:
Common stock			484			—			—			—			484
Treasury stock			(860	)		—			—			—			(860	)
Additional paid-in capital			1,386,475			1,496,510			—			(1,496,510	)		1,386,475
Accumulated deficit			(542,799	)		(789,012	)		—			789,012			(542,799	)
Accumulated other comprehensive income			28,833			28,833			—			(28,833	)		28,833
Total stockholders’ equity			872,133			736,331			—			(736,331	)		872,133
Total liabilities and stockholders’ equity		$	2,000,714		$	1,512,048		$	—			($736,331	)	$	2,776,431
*	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2013
(In thousands)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiary			Guarantor
								Subsidiaries
Operating revenue:
Oil production		$	30,475		$	684,629		$	—		$	—		$	715,104
Gas production			68,895			121,685			—			—			190,580
Natural gas liquids production			32,293			28,394			—			—			60,687
Other operational income			7,163			645			—			—			7,808
Total operating revenue			138,826			835,353			—			—			974,179
Operating expenses:
Lease operating expenses			14,680			186,473			—			—			201,153
Transportation, processing, and gathering expenses			28,322			13,850			—			—			42,172
Production taxes			6,229			8,800			—			—			15,029
Depreciation, depletion, amortization			93,579			256,995			—			—			350,574
Accretion expense			372			33,203			—			—			33,575
Salaries, general and administrative			59,473			5			46			—			59,524
Franchise tax settlement			12,590			—			—			—			12,590
Incentive compensation expense			15,340			—			—			—			15,340
Other operational expenses			38			113			—			—			151
Derivative expense, net			—			2,090			—			—			2,090
Total operating expenses			230,623			501,529			46			—			732,198
Income (loss) from operations			(91,797	)		333,824			(46	)		—			241,981
Other (income) expenses:
Interest expense			32,816			21			—			—			32,837
Interest income			(1,480	)		(195	)		(20	)		—			(1,695	)
Other income			(875	)		(1,924	)		—			—			(2,799	)
Loss on early extinguishment of debt			27,279			—			—			—			27,279
(Income) loss from investment in subsidiaries			(214,983	)		—			26			214,957			—
Total other (income) expenses			(157,243	)		(2,098	)		6			214,957			55,622
Income (loss) before taxes			65,446			335,922			(52	)		(214,957	)		186,359
Provision (benefit) for income taxes:
Current			(10,904	)		—			—			—			(10,904	)
Deferred			(41,284	)		120,913			—			—			79,629
Total income taxes			(52,188	)		120,913			—			—			68,725
Net income (loss)		$	117,634		$	215,009			($52	)		($214,957	)	$	117,634
Comprehensive income (loss)		$	86,739		$	215,009			($52	)		($214,957	)	$	86,739
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2012
(In thousands)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiary			Guarantor
								Subsidiaries
Operating revenue:
Oil production		$	26,149		$	735,155		$	—		$	—		$	761,304
Gas production			34,331			100,408			—			—			134,739
Natural gas liquids production			15,264			33,234			—			—			48,498
Other operational income			2,766			397			357			—			3,520
Derivative income, net			—			3,428			—			—			3,428
Total operating revenue			78,510			872,622			357			—			951,489
Operating expenses:
Lease operating expenses			19,914			195,105			(16	)		—			215,003
Transportation, processing and gathering expenses			12,049			9,733			—			—			21,782
Production taxes			3,330			6,685			—			—			10,015
Depreciation, depletion, amortization			63,022			281,152			191			—			344,365
Accretion expense			561			32,513			257			—			33,331
Salaries, general and administrative			54,641			7			—			—			54,648
Incentive compensation expense			8,113			—			—			—			8,113
Other operational expenses			173			94			—			—			267
Total operating expenses			161,803			525,289			432			—			687,524
Income (loss) from operations			(83,293	)		347,333			(75	)		—			263,965
Other (income) expenses:
Interest expense			30,446			(71	)		—			—			30,375
Interest income			(285	)		(315	)		—			—			(600	)
Other income			(144	)		(1,661	)		—			—			(1,805	)
Loss on early extinguishment of debt			1,972			—			—			—			1,972
(Income) loss from investment in subsidiaries			(223,555	)		75			—			223,480			—
Total other (income) expenses			(191,566	)		(1,972	)		—			223,480			29,942
Income (loss) before taxes			108,273			349,305			(75	)		(223,480	)		234,023
Provision (benefit) for income taxes:
Current			15,022			—			—			—			15,022
Deferred			(56,175	)		125,750			—			—			69,575
Total income taxes			(41,153	)		125,750			—			—			84,597
Net income (loss)		$	149,426		$	223,555			($75	)		($223,480	)	$	149,426
Comprehensive income (loss)		$	156,391		$	223,555			($75	)		($223,480	)	$	156,391
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2011
(In thousands)
		Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
					Subsidiary			Subsidiaries
Operating revenue:
Oil production		$	5,675		$	658,283		$	—		$	—		$	663,958
Gas production			19,470			151,141			—			—			170,611
Natural gas liquids production			—			29,996			—			—			29,996
Other operational income			3,085			249			604			—			3,938
Derivative income, net			—			1,418			—			—			1,418
Total operating revenue			28,230			841,087			604			—			869,921
Operating expenses:
Lease operating expenses			6,632			169,018			231			—			175,881
Transportation, processing and gathering expenses			—			8,958			—			—			8,958
Production taxes			1,434			7,946			—			—			9,380
Depreciation, depletion, amortization			17,860			261,326			834			—			280,020
Accretion expense			15			30,385			364			—			30,764
Salaries, general and administrative			40,073			94			2			—			40,169
Incentive compensation expense			11,600			—			—			—			11,600
Other operational expenses			1,404			745			—			—			2,149
Total operating expenses			79,018			478,472			1,431			—			558,921
Income (loss) from operations			(50,788	)		362,615			(827	)		—			311,000
Other (income) expenses:
Interest expense			9,043			246			—			—			9,289
Interest income			(178	)		(242	)		—			—			(420	)
Other income			(52	)		(1,890	)		—			—			(1,942	)
Loss on early extinguishment of debt			607			—			—			—			607
(Income) loss from investment in subsidiary			(232,751	)		827			—			231,924			—
Total other (income) expenses			(223,331	)		(1,059	)		—			231,924			7,534
Income (loss) before taxes			172,543			363,674			(827	)		(231,924	)		303,466
Provision (benefit) for income taxes:
Current			(20,386	)		—			—			—			(20,386	)
Deferred			(1,403	)		130,923			—			—			129,520
Total income taxes			(21,789	)		130,923			—			—			109,134
Net income (loss)		$	194,332		$	232,751			($827	)		($231,924	)	$	194,332
Comprehensive income (loss)		$	230,404		$	232,751			($827	)		($231,924	)	$	230,404
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2013
(In thousands)
		Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
					Subsidiary			Subsidiaries
Cash flows from operating activities:
Net income (loss)		$	117,634		$	215,009			($52	)		($214,957	)	$	117,634
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			93,579			256,995			—			—			350,574
Accretion expense			372			33,203			—			—			33,575
Deferred income tax provision (benefit)			(41,284	)		120,913			—			—			79,629
Settlement of asset retirement obligations			—			(83,854	)		—			—			(83,854	)
Non-cash stock compensation expense			10,347			—			—			—			10,347
Excess tax benefits			(156	)		—			—			—			(156	)
Non-cash derivative expense			—			2,239			—			—			2,239
Loss on early extinguishment of debt			27,279			—			—			—			27,279
Non-cash interest expense			16,219			—			—			—			16,219
Non-cash (income) loss from investment in subsidiaries			(214,983	)		—			26			214,957			—
Change in current income taxes			2,767			—			—			—			2,767
Change in intercompany receivables/payables			186,903			(186,947	)		44			—			—
(Increase) decrease in accounts receivable			(15,630	)		10,947			—			—			(4,683	)
Decrease in other current assets			1,752			—			—			—			1,752
Decrease in inventory			583			—			—			—			583
Increase (decrease) in accounts payable			(1,052	)		1,454			—			—			402
Increase in other current liabilities			40,543			1,908			—			—			42,451
Other			419			(2,972	)		—			—			(2,553	)
Net cash provided by operating activities			225,292			368,895			18			—			594,205
Cash flows from investing activities:
Investment in oil and gas properties			(273,474	)		(378,254	)		(11,571	)		—			(663,299	)
Proceeds from sale of oil and gas properties, net of expenses			6,300			42,521			—			—			48,821
Investment in fixed and other assets			(6,816	)		—			—			—			(6,816	)
Change in restricted funds			—			—			(1,742	)		—			(1,742	)
Investment in subsidiaries			(14,000	)		—			(13,404	)		27,404			—
Net cash used in investing activities			(287,990	)		(335,733	)		(26,717	)		27,404			(623,036	)
Cash flows from financing activities:
Proceeds from issuance of senior notes			489,250			—			—			—			489,250
Deferred financing costs			(9,065	)		—			—			—			(9,065	)
Redemption of senior notes			(396,014	)		—			—			—			(396,014	)
Excess tax benefits			156			—			—			—			156
Equity proceeds from parent			—			—			27,404			(27,404	)		—
Net payments for share-based compensation			(3,733	)		—			—			—			(3,733	)
Net cash provided by financing activities			80,594			—			27,404			(27,404	)		80,594
Effect of exchange rate changes on cash			—			—			(65	)		—			(65	)
Net change in cash and cash equivalents			17,896			33,162			640			—			51,698
Cash and cash equivalents, beginning of period			228,398			51,128			—			—			279,526
Cash and cash equivalents, end of period		$	246,294		$	84,290		$	640		$	—		$	331,224
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2012
(In thousands)
		Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
					Subsidiary			Subsidiaries
Cash flows from operating activities:
Net income (loss)		$	149,426		$	223,555			($75	)		($223,480	)	$	149,426
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			63,022			281,152			191			—			344,365
Accretion expense			561			32,513			257			—			33,331
Deferred income tax provision (benefit)			(56,175	)		125,750			—			—			69,575
Settlement of asset retirement obligations			—			(65,567	)		—			—			(65,567	)
Non-cash stock compensation expense			8,699			—			—			—			8,699
Excess tax benefits			(949	)		—			—			—			(949	)
Non-cash derivative income			—			(509	)		—			—			(509	)
Loss on early extinguishment of debt			1,972			—			—			—			1,972
Non-cash interest expense			13,085			—			—			—			13,085
Non-cash (income) loss from investment in subsidiaries			(223,555	)		75			—			223,480			—
Change in current income taxes			10,618			—			—			—			10,618
Change in intercompany receivables/payables			275,819			(275,125	)		(694	)		—			—
(Increase) decrease in accounts receivable			(22,750	)		(33,345	)		224			—			(55,871	)
Increase in other current assets			(2,836	)		—			—			—			(2,836	)
Decrease in inventory			436			—			—			—			436
Increase (decrease) in accounts payable			5,348			(208	)		(39	)		—			5,101
Decrease in other current liabilities			(5,311	)		(5,115	)		—			—			(10,426	)
Other			10,960			(1,661	)		—			—			9,299
Net cash provided by (used in) operating activities			228,370			281,515			(136	)		—			509,749
Cash flows from investing activities:
Investment in oil and gas properties			(324,542	)		(231,313	)		—			—			(555,855	)
Proceeds from sale of oil and gas properties, net of expenses			403			—			—			—			403
Sale of fixed assets			134			—			—			—			134
Investment in fixed and other assets			(13,370	)		—			—			—			(13,370	)
Net cash used in investing activities			(337,375	)		(231,313	)		—			—			(568,688	)
Cash flows from financing activities:
Proceeds from bank borrowings			25,000			—			—			—			25,000
Repayment of bank borrowings			(70,000	)		—			—			—			(70,000	)
Proceeds from issuance of senior convertible notes			300,000			—			—			—			300,000
Deferred financing costs of senior convertible notes			(8,855	)		—			—			—			(8,855	)
Proceeds from sold warrants			40,170			—			—			—			40,170
Payments for purchased call options			(70,830	)		—			—			—			(70,830	)
Proceeds from issuance of senior notes			300,000			—			—			—			300,000
Deferred financing costs			(11,966	)		—			—			—			(11,966	)
Redemption of senior subordinated notes			(200,681	)		—			—			—			(200,681	)
Excess tax benefits			949			—			—			—			949
Net payments for share-based compensation			(3,773	)		—			—			—			(3,773	)
Net cash provided by financing activities			300,014			—			—			—			300,014
Net change in cash and cash equivalents			191,009			50,202			(136	)		—			241,075
Cash and cash equivalents, beginning of period			37,389			926			136			—			38,451
Cash and cash equivalents, end of period		$	228,398		$	51,128		$	—		$	—		$	279,526
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2011
(In thousands)
		Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
					Subsidiary			Subsidiaries
Cash flows from operating activities:
Net income (loss)		$	194,332		$	232,751			($827	)		($231,924	)	$	194,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			17,860			261,326			834			—			280,020
Accretion expense			15			30,385			364			—			30,764
Deferred income tax provision (benefit)			(1,403	)		130,923			—			—			129,520
Settlement of asset retirement obligations			—			(63,391	)		—			—			(63,391	)
Non-cash stock compensation expense			5,905			—			—			—			5,905
Excess tax benefits			(1,493	)		—			—			—			(1,493	)
Non-cash derivative income			—			(2,216	)		—			—			(2,216	)
Loss on early extinguishment of debt			607			—			—			—			607
Non-cash interest expense			1,908			—			—			—			1,908
Other non-cash income			(1,602	)		—			—			—			(1,602	)
Non-cash income from investment in subsidiaries			(230,861	)		(1,063	)		—			231,924			—
Change in current income taxes			(19,451	)		—			—			—			(19,451	)
Change in intercompany receivables/payables			217,287			(217,724	)		437			—			—
Increase in accounts receivable			(11,022	)		(7,688	)		(890	)		—			(19,600	)
(Increase) decrease in other current assets			(80	)		14			—			—			(66	)
Decrease in inventory			1,605			14			—			—			1,619
Increase in accounts payable			2,658			3,341			40			—			6,039
Increase in other current liabilities			23,440			6,143			—			—			29,583
Other			(1,628	)		—			—			—			(1,628	)
Net cash provided by (used in) operating activities			198,077			372,815			(42	)		—			570,850
Cash flows from investing activities:
Investment in oil and gas properties			(309,026	)		(455,903	)		(4	)		—			(764,933	)
Proceeds from sale of oil and gas properties, net of expenses			5,575			82,355			—			—			87,930
Investment in fixed and other assets			(2,247	)		—			—			—			(2,247	)
Net cash used in investing activities			(305,698	)		(373,548	)		(4	)		—			(679,250	)
Cash flows from financing activities:
Proceeds from bank borrowings			75,000			—			—			—			75,000
Repayment of bank borrowings			(30,000	)		—			—			—			(30,000	)
Deferred financing costs			(4,017	)		—			—			—			(4,017	)
Excess tax benefits			1,493			—			—			—			1,493
Net payments for share-based compensation			(2,581	)		—			—			—			(2,581	)
Net cash provided by financing activities			39,895			—			—			—			39,895
Net change in cash and cash equivalents			(67,726	)		(733	)		(46	)		—			(68,505	)
Cash and cash equivalents, beginning of period			105,115			1,659			182			—			106,956
Cash and cash equivalents, end of period		$	37,389		$	926		$	136		$	—		$	38,451

ORGANIZATION_AND_SUMMARY_OF_SI1

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of Presentation	'
	Basis of Presentation:
	The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”), Stone Energy Holding, L.L.C., Stone Energy Canada, U.L.C. and Caillou Boca Gathering, LLC (“Caillou Boca”). On September 6, 2012, Caillou Boca was merged into Stone Offshore. All intercompany balances have been eliminated.
Use of Estimates	'
	Use of Estimates:
	The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization (“DD&A”) expense, unevaluated property costs, estimated future net cash flows from proved reserves, costs to abandon oil and gas properties, taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative positions, the purchase price allocation on properties acquired, estimates of fair value in business combinations and contingencies.
Fair Value Measurements	'
	Fair Value Measurements:
	U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2013 and 2012, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in marketable securities. Additionally, fair value concepts were applied in recording the acquisition of various deep water assets in June 2012 and the acquisition of an office building in December 2012.
Hybrid Debt Instruments	'
	Hybrid Debt Instruments:
	In 2012, we issued $300,000 in aggregate principal amount of 1 3⁄4% Senior Convertible Notes due 2017 (the “2017 Convertible Notes”). See Note 11 – Long-Term Debt. On that same day we entered into convertible note hedging transactions which are expected to reduce the potential dilution to our common stock upon conversion of the notes. In accordance with Accounting Standards Codification (“ASC”) 480-20 and ASC 470, we accounted for the debt and equity portions of the notes in a manner that will reflect our nonconvertible borrowing rate when interest is recognized in subsequent periods. This results in the separation of the debt component, classification of the remaining component in stockholders’ equity, and accretion of the resulting discount as part of interest expense. Additionally, the hedging transactions meet the criteria for classification as equity transactions and were recorded as such.
	ASC 260 provides that for contracts that may be settled in common stock or in cash at the election of the entity or the holder, the determination of whether the contract shall be reflected in the computation of diluted earnings per share should be made based on the facts available each period. It is presumed that the contract will be settled in common stock and therefore potential dilution be determined using the if-converted method. However, this presumption may be overcome if past experience or a stated policy provides a reasonable basis to believe that the contract will be settled partially or wholly in cash. Because it is management’s stated intent to redeem the principal amount of the notes in cash, we have used the treasury stock method for determining potential dilution of the notes in our diluted earnings per share computation in accordance with ASC 260.
Business Combinations	'
	Business Combinations:
	Our acquisition in 2012 of various deep water assets was accounted for according to the guidance provided in ASC 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value. Differences between the net fair value of net assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents:
	We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.
Oil and Gas Properties	'
	Oil and Gas Properties:
	We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. We capitalize a portion of the interest costs incurred on our debt based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.
	U.S. GAAP allows the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs and in the computation of DD&A expense. Under the full cost method, all exploratory costs are capitalized while under the successful efforts method exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under the full cost method, DD&A expense is computed on cost centers represented by entire countries while under the successful efforts method cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs.
	We amortize our investment in oil and gas properties through DD&A expense using the units of production (the “UOP”) method. Under the UOP method, the quarterly provision for DD&A expense is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of the period reserves being determined by adding back production to end of the period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.
	Under the full cost method, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows.
	Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Asset Retirement Obligations	'
	Asset Retirement Obligations:
	U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.
Other Property and Equipment	'
	Other Property and Equipment:
	Our office buildings in Lafayette, Louisiana are being depreciated on the straight-line method over their estimated useful life of 39 years.
Inventory	'
	Inventory:
	We maintain an inventory of tubular goods. Items remain in inventory until dedicated to specific projects, at which time they are transferred to oil and gas properties. Items are carried at the lower of cost or market based on the specific identification method.
Earnings Per Common Share	'
	Earnings Per Common Share:
	Under U.S. GAAP, certain instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.
Production Revenue	'
	Production Revenue:
	We recognize production revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production.
Income Taxes	'
	Income Taxes:
	Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures, including future abandonment costs, related to evaluated projects are capitalized and depreciated, depleted and amortized on the UOP method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion, although for 2011, 2012 and 2013, special provisions allowed for current deductions for the cost of certain equipment. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expense, and different reporting methods for employee compensation.
Derivative Instruments and Hedging Activities	'
	Derivative Instruments and Hedging Activities:
	The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments that qualify for cash flow hedge accounting treatment with contemporaneous documentation are recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operations. Instruments not qualifying for hedge accounting treatment are recorded in our balance sheet at fair value, and changes in fair value are recognized in earnings through derivative expense (income).
Share-Based Compensation	'
	Share-Based Compensation:
	We record share-based compensation based on the grant date fair value of issued stock options and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of restricted shares is typically determined based on the average of our high and low stock prices on the grant date.

EARNINGS_PER_SHARE_Tables

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Calculation of Basic and Diluted Weighted Average Shares Outstanding Earnings Per Share	'
	The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods:
		Year Ended December 31,
		2013			2012			2011
	Income (numerator):
	Basic:
	Net income	$	117,634		$	149,426		$	194,332
	Net income attributable to participating securities		(2,817	)		(2,984	)		(3,670	)
	Net income attributable to common stock—basic	$	114,817		$	146,422		$	190,662
	Diluted:
	Net income	$	117,634		$	149,426		$	194,332
	Net income attributable to participating securities		(2,815	)		(2,982	)		(3,667	)
	Net income attributable to common stock—diluted	$	114,819		$	146,444		$	190,665
	Weighted average shares (denominator):
	Weighted average shares—basic		48,693			48,319			47,988
	Dilutive effect of stock options		42			42			42
	Weighted average shares—diluted		48,735			48,361			48,030
	Basic earnings per share	$	2.36		$	3.03		$	3.97
	Diluted earnings per share	$	2.36		$	3.03		$	3.97

ACCOUNTS_RECEIVABLE_Tables

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2013
Receivables [Abstract]	'
Components of Accounts Receivable	'
	Our accounts receivable are comprised of the following amounts:
		As of December 31,
		2013		2012
	Other co-venturers	$	13,904	$	16,735
	Trade		134,622		130,448
	Unbilled accounts receivable		22,001		20,053
	Other		1,444		52
	Total accounts receivable	$	171,971	$	167,288

CONCENTRATIONS_Tables

CONCENTRATIONS (Tables)	12 Months Ended
	Dec. 31, 2013
Risks And Uncertainties [Abstract]	'
Customers from Whom We Derived 10% or More of Total Oil and Gas Revenue	'
	The following table identifies customers from whom we derived 10% or more of our total oil and gas revenue during the years ended:
			December 31,
			2013			2012			2011
	Conoco, Inc.			(a	)		13	%		28	%
	Phillips 66 Company			35	%		18	%		(a	)
	Shell Trading (US) Company			33	%		41	%		46	%
	(a)	Less than 10 percent.

ACQUISITIONS_AND_DIVESTITURES_

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Allocation of Recorded Value of Net Assets Acquired in Transaction	'
	The following represents the allocation of the recorded value of net assets acquired in the transaction.
	Proved oil and gas properties	$	39,221
	Unevaluated oil and gas properties		1,637
	Asset retirement obligations		(14,460	)
	Total fair value of net assets	$	26,398

INVESTMENT_IN_OIL_AND_GAS_PROP1

INVESTMENT IN OIL AND GAS PROPERTIES - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2013
Net Costs Incurred on Unevaluated Properties	'
	The following table discloses net costs incurred (evaluated) on our unevaluated properties located in the United States for the years indicated:
			Year Ended December 31,
			2013			2012			2011
	Unevaluated oil and gas properties – United States:
	Net costs incurred (evaluated) during year:
	Acquisition costs		$	30,271		$	9,739			($2,397	)
	Exploration costs			188,830			(1,209	)		(51,207	)
	Capitalized interest			46,860			37,656			42,033
			$	265,961		$	46,186			($11,571	)
Oil and Gas Related Operating Costs Incurred During and Expensed	'
	Costs incurred during the year (expensed):
	Lease operating expenses		$	201,153		$	215,003		$	175,881
	Transportation, processing and gathering expenses			42,172			21,782			8,958
	Production taxes			15,029			10,015			9,380
	Accretion expense			33,575			33,331			30,764
	Expensed costs – United States		$	291,929		$	280,131		$	224,983
Financial Data Associated with Unevaluated Costs	'
	The following table discloses financial data associated with unevaluated costs (United States and Canada) at December 31, 2013:
			Balance as of			Net Costs Incurred During the
			December 31,			Year Ended December 31,
			2013			2013			2012			2011		2010
														and prior
	Acquisition costs		$	306,793		$	78,555		$	29,959		$	41,442	$	156,837
	Exploration costs			305,422			248,846			56,033			499		44
	Capitalized interest			112,124			39,846			32,755			20,501		19,022
	Total unevaluated costs		$	724,339		$	367,247		$	118,747		$	62,442	$	175,903
United States [Member]	'
Financial Data Relative to Oil and Gas Producing Activities	'
	The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore in the continental United States:
			Year Ended December 31,
			2013			2012			2011
	Oil and gas properties – United States, proved and unevaluated:
	Balance, beginning of year		$	7,692,261		$	7,049,777		$	6,202,758
	Costs incurred during the year (capitalized):
	Acquisition costs, net of sales of unevaluated properties			70,903			102,807			270,354
	Exploratory costs			297,113			81,458			84,199
	Development costs (1)			378,242			395,555			426,355
	Salaries, general and administrative costs			32,815			25,318			24,430
	Interest			46,860			37,656			42,033
	Less: overhead reimbursements			(321	)		(310	)		(352	)
	Total costs incurred during the year, net of divestitures			825,612			642,484			847,019
	Balance, end of year		$	8,517,873		$	7,692,261		$	7,049,777
	Accumulated DD&A:
	Balance, beginning of year		($	5,510,166	)	($	5,174,729	)	($	4,804,949	)
	Provision for DD&A			(346,827	)		(341,096	)		(276,480	)
	Sale of proved properties			(51,767	)		5,659			(93,300	)
	Balance, end of year		($	5,908,760	)	($	5,510,166	)	($	5,174,729	)
	Net capitalized costs – United States, proved and unevaluated		$	2,609,113		$	2,182,095		$	1,875,048
	DD&A per Mcfe		$	3.43		$	3.69		$	3.45
	-1	Includes capitalized asset retirement costs of $54,737, $95,293 and $96,386, respectively.
Canada [Member]	'
Financial Data Relative to Oil and Gas Producing Activities	'
	The following table discloses certain financial data relative to our oil and gas producing activities located in Canada:
			Year Ended
			December 31,
			2013
	Oil and gas properties – Canada, unevaluated:
	Balance, beginning of year		$	—
	Costs incurred during the year (capitalized):
	Acquisition costs			8,764
	Exploratory costs			1,819
	Total costs incurred during the year			10,583
	Balance, end of year, unevaluated		$	10,583

DERIVATIVE_INSTRUMENTS_AND_HED1

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'
Location and Fair Value Amounts of Derivative Instruments Reported in Balance Sheet	'
	The following tables disclose the location and fair value amounts of derivative instruments reported in our balance sheet at December 31, 2013 and December 31, 2012.
	Fair Value of Derivative Instruments at December 31, 2013
			Asset Derivatives						Liability Derivatives
	Description		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of hedging contracts		$	4,549			Current liabilities: Fair value of hedging contracts		$	7,753
			Long-term assets: Fair value of hedging contracts			1,378			Long-term liabilities: Fair value of hedging contracts			470
					$	5,927					$	8,223
	Fair Value of Derivative Instruments at December 31, 2012
			Asset Derivatives						Liability Derivatives
	Description		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of hedging contracts		$	39,655			Current liabilities: Fair value of hedging contracts		$	149
			Long-term assets: Fair value of hedging contracts			9,199			Long-term liabilities: Fair value of hedging contracts			1,530
					$	48,854					$	1,679
Before Tax Effect of Derivative Instruments in Statement of Income	'
	The following table discloses the before tax effect of derivative instruments in the statement of income for the years ended December 31, 2013, 2012 and 2011.
	Effect of Derivative Instruments on the Statement of Income for the Years Ended December 31, 2013, 2012 and 2011
	Derivatives in Cash		Amount of Gain				Gain (Loss) Reclassified from						Gain (Loss) Recognized in Income
	Flow Hedging		(Loss) Recognized				Accumulated Other Comprehensive Income						on Derivatives
	Relationships		in Other				into Income						(Ineffective Portion)
			Comprehensive				(Effective Portion) (a)
			Income on
			Derivatives
							Location						Location
			2013						2013					2013
	Commodity contracts			($26,945	)		Operating revenue—oil/gas production		$	20,289			Derivative expense, net		($2,090	)
	Total			($26,945	)				$	20,289					($2,090	)
			2012						2012					2012
	Commodity contracts		$	41,209			Operating revenue—oil/gas production		$	30,326			Derivative income, net	$	3,428
	Total		$	41,209					$	30,326				$	3,428
			2011						2011					2011
	Commodity contracts		$	43,089			Operating revenue—oil/gas production			($13,274	)		Derivative income, net	$	1,418
	Total		$	43,089						($13,274	)			$	1,418
	(a)	For the year ended December 31, 2013, effective hedging contracts increased oil revenue by $3,520 and increased gas revenue by $16,769. For the year ended December 31, 2012, effective hedging contracts increased oil revenue by $8,546 and increased gas revenue by $21,780. For the year ended December 31, 2011, effective hedging contracts decreased oil revenue by $32,706 and increased gas revenue by $19,432.
Impact of Rights of Offset Associated with Recognized Assets and Liabilities	'
	The following presents the potential impact of the rights of offset associated with our recognized assets and liabilities at December 31, 2013:
			As Presented				Effects of				With Effects
			Without				Netting				of Netting
			Netting
	Current assets: Fair value of hedging contracts		$	4,549			($	4,043	)		$	506
	Long-term assets: Fair value of hedging contracts			1,378				(274	)			1,104
	Current liabilities: Fair value of hedging contracts			(7,753	)			4,043				(3,710	)
	Long-term liabilities: Fair value of hedging contracts			(470	)			274				(196	)
Hedging Positions	'
	The following table illustrates our hedging positions for calendar years 2014, 2015 and 2016 as of February 25, 2014:
			Fixed-Price Swaps
			NYMEX (except where noted)
			Natural Gas								Oil
			Daily				Swap				Daily			Swap
			Volume				Price ($)				Volume			Price ($)
			(MMBtus/d)								(Bbls/d)
	2014			10,000				4				1,000			90.06
	2014			10,000				4.04				1,000			92.25
	2014			10,000				4.105				1,000			93.55
	2014			10,000				4.19				1,000			94
	2014			10,000	(a)			4.25				1,000			98
	2014			10,000				4.25				1,000			98.3
	2014			10,000				4.35				2,000	(b)		98.85
	2014											1,000			99.65
	2014											1,000	(c)		103.3
	2015			10,000				4.005				1,000			90
	2015			10,000				4.12
	2015			10,000				4.15
	2015			10,000				4.165
	2015			10,000				4.22
	2015			10,000				4.255
	2016			10,000				4.11
	2016			10,000				4.12
	(a)	February through December
	(b)	January through June
	(c)	Brent crude oil contract

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of Assets And Liabilities Measured at Fair Value Recurring Basis	'
	The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013:
		Fair Value Measurements at December 31, 2013
	Assets	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Assets		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Marketable securities	$	8,248	$	8,248	$	—	$	—
	Hedging contracts		5,927		—		5,927		—
	Total	$	14,175	$	8,248	$	5,927	$	—
		Fair Value Measurements at December 31, 2013
	Liabilities	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Liabilities		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Hedging contracts	$	8,223	$	—	$	8,223	$	—
	Total	$	8,223	$	—	$	8,223	$	—
	The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2012:
		Fair Value Measurements at December 31, 2012
	Assets	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Assets		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Marketable securities	$	13,492	$	13,492	$	—	$	—
	Hedging contracts		48,854		—		48,854		—
	Total	$	62,346	$	13,492	$	48,854	$	—
		Fair Value Measurements at December 31, 2012
	Liabilities	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Liabilities		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Hedging contracts	$	1,679	$	—	$	1,679	$	—
	Total	$	1,679	$	—	$	1,679	$	—

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Changes in Asset Retirement Obligations	'
	The change in our asset retirement obligations during the years ended December 31, 2013, 2012 and 2011 is set forth below:
		Year Ended December 31,
		2013			2012			2011
	Asset retirement obligations as of the beginning of the year, including current portion	$	488,302		$	425,779		$	373,920
	Liabilities incurred		19,043			3,869			7,993
	Liabilities settled		(79,695	)		(67,641	)		(63,226	)
	Liabilities assumed		—			15,263			59,441
	Divestment of properties		(9,245	)		(7,563	)		(10,900	)
	Accretion expense		33,575			33,331			30,764
	Revision of estimates		50,533			85,264			27,787
	Asset retirement obligations as of the end of the year, including current portion	$	502,513		$	488,302		$	425,779

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Analysis of Deferred Taxes	'
	An analysis of our deferred taxes follows:
		As of December 31,
		2013			2012
	Tax effect of temporary differences:
	Net operating loss carryforwards	$	24,437		$	—
	Oil and gas properties – full cost		(576,393	)		(465,862	)
	Asset retirement obligations		180,905			175,788
	Stock compensation		5,537			5,588
	Hedges		826			(16,983	)
	Accrued incentive compensation		9,189			4,762
	Other		(3,484	)		1,391
			($358,983	)		($295,316	)
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax Rate as a Percentage of Income Before Income Taxes	'
	A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:
		Year Ended December 31,
		2013			2012			2011
	Income tax expense computed at the statutory federal income tax rate		35	%		35	%		35	%
	State taxes		1			1			1
	IRC Sec. 162(m) limitation		0.8			0.6			0.3
	Other		0.1			(0.5	)		(0.3	)
	Effective income tax rate		36.9	%		36.1	%		36	%
Reconciliation Total Amount of Unrecognized Tax Benefits	'
	A reconciliation of the total amounts of unrecognized tax benefits follows:
	Total unrecognized tax benefits as of December 31, 2012	$	385
	Increases (decreases) in unrecognized tax benefits as a result of:		—
	Tax positions taken during a prior period		—
	Tax positions taken during the current period		—
	Settlements with taxing authorities		(385	)
	Lapse of applicable statute of limitations		—
	Total unrecognized tax benefits as of December 31, 2013	$	—

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-term debt consisted of the following:
		As of December 31,
		2013		2012
	8 5⁄8% Senior Notes due 2017	$	—	$	375,000
	1 3⁄4% Senior Convertible Notes due 2017		252,084		239,126
	7 1⁄2% Senior Notes due 2022		775,000		300,000
	Bank debt		—		—
	Total long-term debt	$	1,027,084	$	914,126

ACCUMULATED_OTHER_COMPREHENSIV1

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Changes In Accumulated Other Comprehensive Income Loss	'
	Changes in accumulated other comprehensive income (loss) by component for the year ended December 31, 2013 were as follows:
		Cash			Foreign			Total
		Flow			Currency
		Hedges			Items
	For the Year Ended December 31, 2013
	Beginning balance, net of tax	$	28,833		$	—		$	28,833
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		(26,945	)		—			(26,945	)
	Foreign currency translations		—			(667	)		(667	)
	Income tax effect		9,701			—			9,701
	Net of tax		(17,244	)		(667	)		(17,911	)
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		20,289			—			20,289
	Income tax effect		(7,305	)		—			(7,305	)
	Net of tax		12,984			—			12,984
	Other comprehensive income (loss), net of tax		(30,228	)		(667	)		(30,895	)
	Ending balance, net of tax		($1,395	)		($667	)		($2,062	)
	In 2012 and 2011, the only component of accumulated other comprehensive income (loss) related to our cash flow hedges. Changes in accumulated other comprehensive income (loss) for the years ended December 31, 2012 and 2011 were as follows:
		Cash Flow
		Hedges
	For the Year Ended December 31, 2012
	Beginning balance, net of tax	$	21,868
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		41,209
	Income tax effect		(14,836	)
	Net of tax		26,373
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		30,326
	Income tax effect		(10,918	)
	Net of tax		19,408
	Other comprehensive income, net of tax		6,965
	Ending balance, net of tax	$	28,833
		Cash Flow
		Hedges
	For the Year Ended December 31, 2011
	Beginning balance, net of tax		($14,204	)
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		43,089
	Income tax effect		(15,512	)
	Net of tax		27,577
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		(13,274	)
	Income tax effect		4,779
	Net of tax		(8,495	)
	Other comprehensive income, net of tax		36,072
	Ending balance, net of tax	$	21,868

SHAREBASED_COMPENSATION_Tables

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Summary of Stock Option Activity under Plan	'
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2013 is as follows (amounts in table represent actual values except where indicated otherwise):
		Number			Wgtd.		Wgtd.		Aggregate
		of			Avg.		Avg.		Intrinsic
		Options			Exercise		Term		Value
					Price				(in thousands)
	Options outstanding, beginning of period		411,794		$	39.04
	Granted		—			—
	Exercised		—			—
	Forfeited		(15,250	)		42.45
	Expired		(65,370	)		36.56
	Options outstanding, end of period		331,174			39.37	2.2 years		$	1,708
	Options exercisable, end of period		318,279			40.62	2.1 years			1,373
	Options unvested, end of period		12,895			8.64	5.0 years			335
	Exercise prices for stock options outstanding at December 31, 2013 range from $6.97 to $53.20.
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2012 is as follows (amounts in table represent actual values except where indicated otherwise):
		Number			Wgtd.		Wgtd.		Aggregate
		of			Avg.		Avg.		Intrinsic
		Options			Exercise		Term		Value
					Price				(in thousands)
	Options outstanding, beginning of period		438,394		$	38.76
	Granted		—			—
	Exercised		—			—
	Forfeited		(4,200	)		35.54
	Expired		(22,400	)		34.25
	Options outstanding, end of period		411,794			39.04	2.8 years		$	766
	Options exercisable, end of period		378,004			41	2.5 years			459
	Options unvested, end of period		33,790			17.17	5.4 years			307
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2011 is as follows (amounts in table represent actual values except where indicated otherwise):
		Number			Wgtd.		Wgtd.		Aggregate
		of			Avg.		Avg.		Intrinsic
		Options			Exercise		Term		Value
					Price				(in thousands)
	Options outstanding, beginning of period		484,694		$	39.43
	Granted		—			—
	Exercised		—			—
	Forfeited		(13,300	)		37.98
	Expired		(33,000	)		48.85
	Options outstanding, end of period		438,394			38.76	3.6 years		$	1,143
	Options exercisable, end of period		378,710			41.66	3.1 years			457
	Options unvested, end of period		59,684			20.36	6.1 years			686
Summary of Restricted Stock Activity Under Plan	'
	A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2013, 2012 and 2011 is as follows (amounts in table represent actual values):
		2013					2012						2011
		Number of			Wgtd.		Number of				Wgtd.		Number of			Wgtd.
		Restricted			Avg.		Restricted				Avg.		Restricted			Avg.
		Shares			Fair Value		Shares				Fair Value		Shares			Fair Value
					Per Share						Per Share					Per Share
	Restricted stock outstanding, beginning of period		1,108,874		$	27.56		923,740			$	20.08		783,606		$	17.24
	Issuances		848,498			20.61		670,818				31.43		597,062			23.62
	Lapse of restrictions		(534,041	)		25.45		(462,141	)			18.29		(419,543	)		19.91
	Forfeitures		(165,278	)		26.43		(23,543	)			26.1		(37,385	)		18.92
	Restricted stock outstanding, end of period		1,258,053		$	23.92		1,108,874			$	27.56		923,740		$	20.08

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Minimum Net Annual Commitments Under all Leases, Subleases and Contracts with Non-Cancelable Terms in Excess of 12 Months	'
	The minimum net annual commitments under all leases, subleases and contracts with non-cancelable terms in excess of 12 months at December 31, 2013 were as follows:
	2014	$	736
	2015		637
	2016		358
	2017		301
	2018		147

OIL_AND_GAS_RESERVE_INFORMATIO1

OIL AND GAS RESERVE INFORMATION - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Summary of Estimated Proved Oil and Natural Gas Reserve	'
	Reserve volumes for the year ended December 31, 2010 have not been reclassified to conform to the current presentation given the immateriality of NGL volumes in such period.
		Oil			NGLs			Natural			Oil,
		(MBbls)			(MBbls)			Gas			Natural
								(MMcf)			Gas and
											NGLs
											(MMcfe)
	Estimated proved reserves as of December 31, 2010		33,203			—			274,705			473,923
	Revisions of previous estimates		2,889			4,911			(26,725	)		20,075
	Extensions, discoveries and other additions		3,544			—			93,520			114,784
	Purchase of producing properties		14,396			—			24,595			110,971
	Sale of reserves		(1,950	)		—			(2,150	)		(13,850	)
	Production		(6,427	)		(506	)		(38,466	)		(80,064	)
	Estimated proved reserves as of December 31, 2011		45,655			4,405			325,479			625,839
	Revisions of previous estimates		(1,559	)		9,349			(26,694	)		20,050
	Extensions, discoveries and other additions		3,681			4,856			131,408			182,633
	Purchase of producing properties		4,336			619			8,168			37,895
	Sale of reserves		(60	)		—			(418	)		(775	)
	Production		(7,135	)		(1,163	)		(42,569	)		(92,357	)
	Estimated proved reserves as of December 31, 2012		44,918			18,066			395,374			773,285
	Revisions of previous estimates		3,606			2,439			36,006			72,275
	Extensions, discoveries and other additions		2,367			4,395			79,729			120,299
	Sale of reserves		(170	)		—			(214	)		(1,235	)
	Production		(6,894	)		(1,603	)		(50,129	)		(101,111	)
	Estimated proved reserves as of December 31, 2013		43,827			23,297			460,766			863,513
	Estimated proved developed reserves:
	as of December 31, 2011		30,914			3,195			171,871			376,528
	as of December 31, 2012		29,005			8,593			210,956			436,540
	as of December 31, 2013		27,920			11,569			246,946			483,885
Summary of Standardized Measure of Discounted Future Net Cash Flows	'
		Standardized Measure Year Ended December 31,
		2013			2012			2011
	Future cash inflows	$	7,040,928		$	6,295,455		$	6,171,279
	Future production costs		(2,062,657	)		(1,946,426	)		(1,747,806	)
	Future development costs		(1,431,101	)		(1,241,531	)		(1,219,214	)
	Future income taxes		(884,637	)		(799,007	)		(852,364	)
	Future net cash flows		2,662,533			2,308,491			2,351,895
	10% annual discount		(977,531	)		(794,632	)		(808,933	)
	Standardized measure of discounted future net cash flows	$	1,685,002		$	1,513,859		$	1,542,962
		Changes in Standardized Measure
		Year Ended December 31,
		2013			2012			2011
	Standardized measure at beginning of year	$	1,513,859		$	1,542,962		$	957,629
	Sales and transfers of oil, gas and NGLs produced, net of production costs		(708,017	)		(697,741	)		(670,347	)
	Changes in price, net of future production costs		229,425			(380,841	)		502,324
	Extensions and discoveries, net of future production and development costs		155,592			178,272			293,168
	Changes in estimated future development costs, net of development costs incurred during the period		28,684			212,329			97,852
	Revisions of quantity estimates		281,558			76,450			(27,854	)
	Accretion of discount		202,087			207,292			118,722
	Net change in income taxes		(28,084	)		22,947			(300,363	)
	Purchases of reserves in-place		—			276,389			567,286
	Sales of reserves in-place		15,531			2,480			(36,278	)
	Changes in production rates due to timing and other		(5,633	)		73,320			40,823
	Net increase (decrease) in standardized measure		171,143			(29,103	)		585,333
	Standardized measure at end of year	$	1,685,002		$	1,513,859		$	1,542,962

SUMMARIZED_QUARTERLY_FINANCIAL1

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Results of Operations by Quarter	'
	The results of operations by quarter are as follows:
			2013 Quarter Ended
			March 31		June 30		September 30		December 31
	Operating revenue		$	233,732	$	245,877	$	256,685	$	239,253
	Income from operations			72,828		69,525		62,422		37,206	(a)
	Net income			40,758		39,022		36,102		1,752	(a) (b)
	Basic earnings per share		$	0.82	$	0.78	$	0.72	$	0.04
	Diluted earnings per share		$	0.82	$	0.78	$	0.72	$	0.04
			2012 Quarter Ended
			March 31		June 30		September 30		December 31
	Operating revenue		$	244,957	$	226,561	$	227,397	$	254,871
	Income from operations			84,927		56,156		44,485		78,397
	Net income			50,974		30,547		23,659		44,246
	Basic earnings per share		$	1.04	$	0.62	$	0.48	$	0.89
	Diluted earnings per share		$	1.04	$	0.62	$	0.48	$	0.89
	(a)	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
	(b)	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

GUARANTOR_FINANCIAL_STATEMENTS1

GUARANTOR FINANCIAL STATEMENTS (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Condensed Consolidating Balance Sheet	'
	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-13
	(In thousands)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiary			Subsidiaries
	Assets
	Current assets:
	Cash and cash equivalents		$	246,294		$	84,290		$	640		$	—		$	331,224
	Accounts receivable			74,887			97,128			—			(44	)		171,971
	Fair value of hedging contracts			—			4,549			—			—			4,549
	Current income tax receivable			7,366			—			—			—			7,366
	Deferred taxes *			8,659			23,051			—			—			31,710
	Inventory			3,440			283			—			—			3,723
	Other current assets			1,874			—			—			—			1,874
	Total current assets			342,520			209,301			640			(44	)		552,417
	Oil and gas properties, full cost method:
	Proved			1,309,527			6,494,590			—			—			7,804,117
	Less: accumulated DD&A			(459,932	)		(5,448,828	)		—			—			(5,908,760	)
	Net proved oil and gas properties			849,595			1,045,762			—			—			1,895,357
	Unevaluated			325,113			388,643			10,583			—			724,339
	Other property and equipment, net			26,178			—			—			—			26,178
	Fair value of hedging contracts			—			1,378			—			—			1,378
	Other assets, net			45,410			1,349			2,128			—			48,887
	Investment in subsidiary			747,472			—			12,711			(760,183	)		—
	Total assets		$	2,336,288		$	1,646,433		$	26,062			($760,227	)	$	3,248,556
	Liabilities and Stockholders’ Equity
	Current liabilities:
	Accounts payable to vendors		$	173,147		$	22,530		$	44			($44	)	$	195,677
	Undistributed oil and gas proceeds			34,386			2,643			—			—			37,029
	Accrued interest			9,022			—			—			—			9,022
	Fair value of hedging contracts			—			7,753			—			—			7,753
	Asset retirement obligations			—			67,161			—			—			67,161
	Other current liabilities			53,682			838			—			—			54,520
	Total current liabilities			270,237			100,925			44			(44	)		371,162
	Long-term debt			1,027,084			—			—			—			1,027,084
	Deferred taxes *			10,227			380,466			—			—			390,693
	Asset retirement obligations			4,945			430,407			—			—			435,352
	Fair value of hedging contracts			—			470			—			—			470
	Other long-term liabilities			53,509			—			—			—			53,509
	Total liabilities			1,366,002			912,268			44			(44	)		2,278,270
	Commitments and contingencies Stockholders’ equity:
	Common stock			488			—			—			—			488
	Treasury stock			(860	)		—			—			—			(860	)
	Additional paid-in capital			1,397,885			1,309,563			27,403			(1,336,966	)		1,397,885
	Accumulated deficit			(425,165	)		(574,003	)		(52	)		574,055			(425,165	)
	Accumulated other comprehensive loss			(2,062	)		(1,395	)		(1,333	)		2,728			(2,062	)
	Total stockholders’ equity			970,286			734,165			26,018			(760,183	)		970,286
	Total liabilities and stockholders’ equity		$	2,336,288		$	1,646,433		$	26,062			($760,227	)	$	3,248,556
	*	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.
	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-12
	(In thousands)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiary			Subsidiaries
	Assets
	Current assets:
	Cash and cash equivalents		$	228,398		$	51,128		$	—		$	—		$	279,526
	Accounts receivable			59,213			108,075			—			—			167,288
	Fair value of hedging contracts			—			39,655			—			—			39,655
	Current income tax receivable			10,027			—			—			—			10,027
	Deferred taxes *			5,947			9,567			—			—			15,514
	Inventory			3,924			283			—			—			4,207
	Other current assets			3,626			—			—			—			3,626
Total current assets			311,135			208,708			—			—			519,843
Oil and gas properties, full cost method:
Proved			1,004,808			6,239,658			—			—			7,244,466
Less: accumulated DD&A			(370,111	)		(5,140,055	)		—			—			(5,510,166	)
Net proved oil and gas properties			634,697			1,099,603			—			—			1,734,300
Unevaluated			254,757			193,038			—			—			447,795
Other property and equipment, net			22,115			—			—			—			22,115
Fair value of hedging contracts			—			9,199			—			—			9,199
Other assets, net			41,679			1,500			—			—			43,179
Investment in subsidiary			736,331			—			—			(736,331	)		—
Total assets		$	2,000,714		$	1,512,048		$	—			($736,331	)	$	2,776,431
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors		$	74,503		$	19,858		$	—		$	—		$	94,361
Undistributed oil and gas proceeds			21,841			1,573			—			—			23,414
Accrued interest			18,546			—			—			—			18,546
Fair value of hedging contracts			—			149			—			—			149
Asset retirement obligations			—			66,260			—			—			66,260
Other current liabilities			16,765			—			—			—			16,765
Total current liabilities			131,655			87,840			—			—			219,495
Long-term debt			914,126			—			—			—			914,126
Deferred taxes *			47,758			263,072			—			—			310,830
Asset retirement obligations			5,479			416,563			—			—			422,042
Fair value of hedging contracts			—			1,530			—			—			1,530
Other long-term liabilities			29,563			6,712			—			—			36,275
Total liabilities			1,128,581			775,717			—			—			1,904,298
Commitments and contingencies Stockholders’ equity:
Common stock			484			—			—			—			484
Treasury stock			(860	)		—			—			—			(860	)
Additional paid-in capital			1,386,475			1,496,510			—			(1,496,510	)		1,386,475
Accumulated deficit			(542,799	)		(789,012	)		—			789,012			(542,799	)
Accumulated other comprehensive income			28,833			28,833			—			(28,833	)		28,833
Total stockholders’ equity			872,133			736,331			—			(736,331	)		872,133
Total liabilities and stockholders’ equity		$	2,000,714		$	1,512,048		$	—			($736,331	)	$	2,776,431
*	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.
Condensed Consolidating Statement of Income	'
	CONDENSED CONSOLIDATING STATEMENT OF INCOME
	YEAR ENDED DECEMBER 31, 2013
	(In thousands)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiary			Guarantor
									Subsidiaries
	Operating revenue:
	Oil production		$	30,475		$	684,629		$	—		$	—		$	715,104
	Gas production			68,895			121,685			—			—			190,580
	Natural gas liquids production			32,293			28,394			—			—			60,687
	Other operational income			7,163			645			—			—			7,808
	Total operating revenue			138,826			835,353			—			—			974,179
	Operating expenses:
	Lease operating expenses			14,680			186,473			—			—			201,153
	Transportation, processing, and gathering expenses			28,322			13,850			—			—			42,172
	Production taxes			6,229			8,800			—			—			15,029
	Depreciation, depletion, amortization			93,579			256,995			—			—			350,574
	Accretion expense			372			33,203			—			—			33,575
	Salaries, general and administrative			59,473			5			46			—			59,524
	Franchise tax settlement			12,590			—			—			—			12,590
	Incentive compensation expense			15,340			—			—			—			15,340
	Other operational expenses			38			113			—			—			151
	Derivative expense, net			—			2,090			—			—			2,090
	Total operating expenses			230,623			501,529			46			—			732,198
	Income (loss) from operations			(91,797	)		333,824			(46	)		—			241,981
	Other (income) expenses:
	Interest expense			32,816			21			—			—			32,837
	Interest income			(1,480	)		(195	)		(20	)		—			(1,695	)
	Other income			(875	)		(1,924	)		—			—			(2,799	)
	Loss on early extinguishment of debt			27,279			—			—			—			27,279
	(Income) loss from investment in subsidiaries			(214,983	)		—			26			214,957			—
	Total other (income) expenses			(157,243	)		(2,098	)		6			214,957			55,622
	Income (loss) before taxes			65,446			335,922			(52	)		(214,957	)		186,359
	Provision (benefit) for income taxes:
	Current			(10,904	)		—			—			—			(10,904	)
	Deferred			(41,284	)		120,913			—			—			79,629
	Total income taxes			(52,188	)		120,913			—			—			68,725
	Net income (loss)		$	117,634		$	215,009			($52	)		($214,957	)	$	117,634
	Comprehensive income (loss)		$	86,739		$	215,009			($52	)		($214,957	)	$	86,739
	CONDENSED CONSOLIDATING STATEMENT OF INCOME
	YEAR ENDED DECEMBER 31, 2012
	(In thousands)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiary			Guarantor
									Subsidiaries
	Operating revenue:
	Oil production		$	26,149		$	735,155		$	—		$	—		$	761,304
	Gas production			34,331			100,408			—			—			134,739
	Natural gas liquids production			15,264			33,234			—			—			48,498
	Other operational income			2,766			397			357			—			3,520
	Derivative income, net			—			3,428			—			—			3,428
	Total operating revenue			78,510			872,622			357			—			951,489
	Operating expenses:
	Lease operating expenses			19,914			195,105			(16	)		—			215,003
	Transportation, processing and gathering expenses			12,049			9,733			—			—			21,782
	Production taxes			3,330			6,685			—			—			10,015
	Depreciation, depletion, amortization			63,022			281,152			191			—			344,365
	Accretion expense			561			32,513			257			—			33,331
	Salaries, general and administrative			54,641			7			—			—			54,648
	Incentive compensation expense			8,113			—			—			—			8,113
	Other operational expenses			173			94			—			—			267
	Total operating expenses			161,803			525,289			432			—			687,524
	Income (loss) from operations			(83,293	)		347,333			(75	)		—			263,965
Other (income) expenses:
Interest expense			30,446			(71	)		—			—			30,375
Interest income			(285	)		(315	)		—			—			(600	)
Other income			(144	)		(1,661	)		—			—			(1,805	)
Loss on early extinguishment of debt			1,972			—			—			—			1,972
(Income) loss from investment in subsidiaries			(223,555	)		75			—			223,480			—
Total other (income) expenses			(191,566	)		(1,972	)		—			223,480			29,942
Income (loss) before taxes			108,273			349,305			(75	)		(223,480	)		234,023
Provision (benefit) for income taxes:
Current			15,022			—			—			—			15,022
Deferred			(56,175	)		125,750			—			—			69,575
Total income taxes			(41,153	)		125,750			—			—			84,597
Net income (loss)		$	149,426		$	223,555			($75	)		($223,480	)	$	149,426
Comprehensive income (loss)		$	156,391		$	223,555			($75	)		($223,480	)	$	156,391
CONDENSED CONSOLIDATING STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 2011
(In thousands)
		Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
					Subsidiary			Subsidiaries
Operating revenue:
Oil production		$	5,675		$	658,283		$	—		$	—		$	663,958
Gas production			19,470			151,141			—			—			170,611
Natural gas liquids production			—			29,996			—			—			29,996
Other operational income			3,085			249			604			—			3,938
Derivative income, net			—			1,418			—			—			1,418
Total operating revenue			28,230			841,087			604			—			869,921
Operating expenses:
Lease operating expenses			6,632			169,018			231			—			175,881
Transportation, processing and gathering expenses			—			8,958			—			—			8,958
Production taxes			1,434			7,946			—			—			9,380
Depreciation, depletion, amortization			17,860			261,326			834			—			280,020
Accretion expense			15			30,385			364			—			30,764
Salaries, general and administrative			40,073			94			2			—			40,169
Incentive compensation expense			11,600			—			—			—			11,600
Other operational expenses			1,404			745			—			—			2,149
Total operating expenses			79,018			478,472			1,431			—			558,921
Income (loss) from operations			(50,788	)		362,615			(827	)		—			311,000
Other (income) expenses:
Interest expense			9,043			246			—			—			9,289
Interest income			(178	)		(242	)		—			—			(420	)
Other income			(52	)		(1,890	)		—			—			(1,942	)
Loss on early extinguishment of debt			607			—			—			—			607
(Income) loss from investment in subsidiary			(232,751	)		827			—			231,924			—
Total other (income) expenses			(223,331	)		(1,059	)		—			231,924			7,534
Income (loss) before taxes			172,543			363,674			(827	)		(231,924	)		303,466
Provision (benefit) for income taxes:
Current			(20,386	)		—			—			—			(20,386	)
Deferred			(1,403	)		130,923			—			—			129,520
Total income taxes			(21,789	)		130,923			—			—			109,134
Net income (loss)		$	194,332		$	232,751			($827	)		($231,924	)	$	194,332
Comprehensive income (loss)		$	230,404		$	232,751			($827	)		($231,924	)	$	230,404
Condensed Consolidating Statement of Cash Flows	'
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2013
	(In thousands)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiary			Subsidiaries
	Cash flows from operating activities:
	Net income (loss)		$	117,634		$	215,009			($52	)		($214,957	)	$	117,634
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion and amortization			93,579			256,995			—			—			350,574
	Accretion expense			372			33,203			—			—			33,575
	Deferred income tax provision (benefit)			(41,284	)		120,913			—			—			79,629
	Settlement of asset retirement obligations			—			(83,854	)		—			—			(83,854	)
	Non-cash stock compensation expense			10,347			—			—			—			10,347
	Excess tax benefits			(156	)		—			—			—			(156	)
	Non-cash derivative expense			—			2,239			—			—			2,239
	Loss on early extinguishment of debt			27,279			—			—			—			27,279
	Non-cash interest expense			16,219			—			—			—			16,219
	Non-cash (income) loss from investment in subsidiaries			(214,983	)		—			26			214,957			—
	Change in current income taxes			2,767			—			—			—			2,767
	Change in intercompany receivables/payables			186,903			(186,947	)		44			—			—
	(Increase) decrease in accounts receivable			(15,630	)		10,947			—			—			(4,683	)
	Decrease in other current assets			1,752			—			—			—			1,752
	Decrease in inventory			583			—			—			—			583
	Increase (decrease) in accounts payable			(1,052	)		1,454			—			—			402
	Increase in other current liabilities			40,543			1,908			—			—			42,451
	Other			419			(2,972	)		—			—			(2,553	)
	Net cash provided by operating activities			225,292			368,895			18			—			594,205
	Cash flows from investing activities:
	Investment in oil and gas properties			(273,474	)		(378,254	)		(11,571	)		—			(663,299	)
	Proceeds from sale of oil and gas properties, net of expenses			6,300			42,521			—			—			48,821
	Investment in fixed and other assets			(6,816	)		—			—			—			(6,816	)
	Change in restricted funds			—			—			(1,742	)		—			(1,742	)
	Investment in subsidiaries			(14,000	)		—			(13,404	)		27,404			—
	Net cash used in investing activities			(287,990	)		(335,733	)		(26,717	)		27,404			(623,036	)
	Cash flows from financing activities:
	Proceeds from issuance of senior notes			489,250			—			—			—			489,250
	Deferred financing costs			(9,065	)		—			—			—			(9,065	)
	Redemption of senior notes			(396,014	)		—			—			—			(396,014	)
	Excess tax benefits			156			—			—			—			156
	Equity proceeds from parent			—			—			27,404			(27,404	)		—
	Net payments for share-based compensation			(3,733	)		—			—			—			(3,733	)
	Net cash provided by financing activities			80,594			—			27,404			(27,404	)		80,594
	Effect of exchange rate changes on cash			—			—			(65	)		—			(65	)
	Net change in cash and cash equivalents			17,896			33,162			640			—			51,698
	Cash and cash equivalents, beginning of period			228,398			51,128			—			—			279,526
	Cash and cash equivalents, end of period		$	246,294		$	84,290		$	640		$	—		$	331,224
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2012
	(In thousands)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiary			Subsidiaries
	Cash flows from operating activities:
	Net income (loss)		$	149,426		$	223,555			($75	)		($223,480	)	$	149,426
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion and amortization			63,022			281,152			191			—			344,365
	Accretion expense			561			32,513			257			—			33,331
	Deferred income tax provision (benefit)			(56,175	)		125,750			—			—			69,575
	Settlement of asset retirement obligations			—			(65,567	)		—			—			(65,567	)
	Non-cash stock compensation expense			8,699			—			—			—			8,699
	Excess tax benefits			(949	)		—			—			—			(949	)
	Non-cash derivative income			—			(509	)		—			—			(509	)
	Loss on early extinguishment of debt			1,972			—			—			—			1,972
	Non-cash interest expense			13,085			—			—			—			13,085
Non-cash (income) loss from investment in subsidiaries			(223,555	)		75			—			223,480			—
Change in current income taxes			10,618			—			—			—			10,618
Change in intercompany receivables/payables			275,819			(275,125	)		(694	)		—			—
(Increase) decrease in accounts receivable			(22,750	)		(33,345	)		224			—			(55,871	)
Increase in other current assets			(2,836	)		—			—			—			(2,836	)
Decrease in inventory			436			—			—			—			436
Increase (decrease) in accounts payable			5,348			(208	)		(39	)		—			5,101
Decrease in other current liabilities			(5,311	)		(5,115	)		—			—			(10,426	)
Other			10,960			(1,661	)		—			—			9,299
Net cash provided by (used in) operating activities			228,370			281,515			(136	)		—			509,749
Cash flows from investing activities:
Investment in oil and gas properties			(324,542	)		(231,313	)		—			—			(555,855	)
Proceeds from sale of oil and gas properties, net of expenses			403			—			—			—			403
Sale of fixed assets			134			—			—			—			134
Investment in fixed and other assets			(13,370	)		—			—			—			(13,370	)
Net cash used in investing activities			(337,375	)		(231,313	)		—			—			(568,688	)
Cash flows from financing activities:
Proceeds from bank borrowings			25,000			—			—			—			25,000
Repayment of bank borrowings			(70,000	)		—			—			—			(70,000	)
Proceeds from issuance of senior convertible notes			300,000			—			—			—			300,000
Deferred financing costs of senior convertible notes			(8,855	)		—			—			—			(8,855	)
Proceeds from sold warrants			40,170			—			—			—			40,170
Payments for purchased call options			(70,830	)		—			—			—			(70,830	)
Proceeds from issuance of senior notes			300,000			—			—			—			300,000
Deferred financing costs			(11,966	)		—			—			—			(11,966	)
Redemption of senior subordinated notes			(200,681	)		—			—			—			(200,681	)
Excess tax benefits			949			—			—			—			949
Net payments for share-based compensation			(3,773	)		—			—			—			(3,773	)
Net cash provided by financing activities			300,014			—			—			—			300,014
Net change in cash and cash equivalents			191,009			50,202			(136	)		—			241,075
Cash and cash equivalents, beginning of period			37,389			926			136			—			38,451
Cash and cash equivalents, end of period		$	228,398		$	51,128		$	—		$	—		$	279,526
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2011
(In thousands)
		Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
					Subsidiary			Subsidiaries
Cash flows from operating activities:
Net income (loss)		$	194,332		$	232,751			($827	)		($231,924	)	$	194,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			17,860			261,326			834			—			280,020
Accretion expense			15			30,385			364			—			30,764
Deferred income tax provision (benefit)			(1,403	)		130,923			—			—			129,520
Settlement of asset retirement obligations			—			(63,391	)		—			—			(63,391	)
Non-cash stock compensation expense			5,905			—			—			—			5,905
Excess tax benefits			(1,493	)		—			—			—			(1,493	)
Non-cash derivative income			—			(2,216	)		—			—			(2,216	)
Loss on early extinguishment of debt			607			—			—			—			607
Non-cash interest expense			1,908			—			—			—			1,908
Other non-cash income			(1,602	)		—			—			—			(1,602	)
Non-cash income from investment in subsidiaries			(230,861	)		(1,063	)		—			231,924			—
Change in current income taxes			(19,451	)		—			—			—			(19,451	)
Change in intercompany receivables/payables			217,287			(217,724	)		437			—			—
Increase in accounts receivable			(11,022	)		(7,688	)		(890	)		—			(19,600	)
(Increase) decrease in other current assets			(80	)		14			—			—			(66	)
Decrease in inventory			1,605			14			—			—			1,619
Increase in accounts payable			2,658			3,341			40			—			6,039
Increase in other current liabilities			23,440			6,143			—			—			29,583
Other			(1,628	)		—			—			—			(1,628	)
Net cash provided by (used in) operating activities			198,077			372,815			(42	)		—			570,850
Cash flows from investing activities:
Investment in oil and gas properties			(309,026	)		(455,903	)		(4	)		—			(764,933	)
Proceeds from sale of oil and gas properties, net of expenses			5,575			82,355			—			—			87,930
Investment in fixed and other assets			(2,247	)		—			—			—			(2,247	)
Net cash used in investing activities			(305,698	)		(373,548	)		(4	)		—			(679,250	)
Cash flows from financing activities:
Proceeds from bank borrowings			75,000			—			—			—			75,000
Repayment of bank borrowings			(30,000	)		—			—			—			(30,000	)
Deferred financing costs			(4,017	)		—			—			—			(4,017	)
Excess tax benefits			1,493			—			—			—			1,493
Net payments for share-based compensation			(2,581	)		—			—			—			(2,581	)
Net cash provided by financing activities			39,895			—			—			—			39,895
Net change in cash and cash equivalents			(67,726	)		(733	)		(46	)		—			(68,505	)
Cash and cash equivalents, beginning of period			105,115			1,659			182			—			106,956
Cash and cash equivalents, end of period		$	37,389		$	926		$	136		$	—		$	38,451

Recovered_Sheet1

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Mar. 06, 2012
	Building [Member]	1.75% Senior Convertible Notes due 2017 [Member]	1.75% Senior Convertible Notes due 2017 [Member]
Schedule Of Significant Accounting Policies [Line Items]	'	'	'
Aggregate principal amount of debt issued	'	$300,000	$300,000
Senior convertible note, maturity year	'	'2017	'
Senior convertible note, stated interest rate	'	1.75%	'
Estimated useful life of Building	'39 years	'	'

Calculation_of_Basic_and_Dilut

Calculation of Basic and Diluted Weighted Average Shares Outstanding and Earnings Per Share (Detail) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Basic:

'

'

'

'

'

'

'

'

'

'

'

Net income

$1,752

[1],[2]

$36,102

$39,022

$40,758

$44,246

$23,659

$30,547

$50,974

$117,634

$149,426

$194,332

Net income attributable to participating securities

'

'

'

'

'

'

'

'

-2,817

-2,984

-3,670

Net income attributable to common stock-basic

'

'

'

'

'

'

'

'

114,817

146,422

190,662

Diluted:

'

'

'

'

'

'

'

'

'

'

'

Net income

1,752

[1],[2]

36,102

39,022

40,758

44,246

23,659

30,547

50,974

117,634

149,426

194,332

Net income attributable to participating securities

'

'

'

'

'

'

'

'

-2,815

-2,982

-3,667

Net income attributable to common stock-diluted

'

'

'

'

'

'

'

'

$114,819

$146,444

$190,665

Weighted average shares (denominator):

'

'

'

'

'

'

'

'

'

'

'

Weighted average shares-basic

'

'

'

'

'

'

'

'

48,693

48,319

47,988

Dilutive effect of stock options

'

'

'

'

'

'

'

'

42

42

42

Weighted average shares-diluted

'

'

'

'

'

'

'

'

48,735

48,361

48,030

Basic earnings per share

$0.04

$0.72

$0.78

$0.82

$0.89

$0.48

$0.62

$1.04

$2.36

$3.03

$3.97

Diluted earnings per share

$0.04

$0.72

$0.78

$0.82

$0.89

$0.48

$0.62

$1.04

$2.36

$3.03

$3.97

[1]

Includes franchise tax settlement of $12,590 before income tax effect ($8,058, net of income tax effect).

[2]

Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

Earnings_Per_Share_Additional_

Earnings Per Share - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]	'	'	'
Antidilutive stock options outstanding	242,000	347,000	374,000
Shares of common stock issued upon vesting of restricted stock	358,000	316,000	312,000

Components_of_Accounts_Receiva

Components of Accounts Receivable (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Receivables [Abstract]	'	'
Other co-venturers	$13,904	$16,735
Trade	134,622	130,448
Unbilled accounts receivable	22,001	20,053
Other	1,444	52
Total accounts receivable	$171,971	$167,288

Customers_from_Whom_We_Derived

Customers from Whom We Derived Ten Percent or More of Total Oil and Gas Revenue (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Conoco, Inc [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Customers from whom 10% or more revenue derived	'	13.00%	28.00%
Concentration risk, benchmark description	'Less than 10%	'	'
Phillips 66 Company [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Customers from whom 10% or more revenue derived	35.00%	18.00%	'
Concentration risk, benchmark description	'	'	'Less than 10%
Shell Trading (US) Company [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Customers from whom 10% or more revenue derived	33.00%	41.00%	46.00%

Concentrations_Additional_Info

Concentrations - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Unusual Risk or Uncertainty [Line Items]	'
Maximum amount of credit risk exposure	74,273
Gulf Coast Basin Conventional Shelf and deep gas Properties [Member]	'
Unusual Risk or Uncertainty [Line Items]	'
Production associated with properties	49.00%
Estimated proved reserves derived	16.00%
Deep Water Properties [Member]	'
Unusual Risk or Uncertainty [Line Items]	'
Production associated with properties	25.00%
Estimated proved reserves derived	29.00%
Appalachian Properties [Member]	'
Unusual Risk or Uncertainty [Line Items]	'
Production associated with properties	26.00%
Estimated proved reserves derived	55.00%

Recovered_Sheet2

Acquisitions and Divestitures - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Jun. 18, 2012	Oct. 31, 2013	Jun. 18, 2012	Jun. 18, 2012	Jun. 18, 2012
				Weeks Island Field [Member]	Block Deep Water Pompano Field Mississippi Canyon [Member]	Mississippi Canyon Block 29 [Member]	Mississippi Canyon Block 72 [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Fair value of Land and Building at the time of Acquisition	$8,539	'	'	'	'	'	'
Purchase Consideration	8,539	'	'	'	'	'	'
Percentage of working interest acquired	'	'	'	'	25.00%	14.00%	10.00%
Cash consideration transferred	'	26,398	26,398	'	'	'	'
Sale of interest cash consideration	'	'	'	42,957	'	'	'
Estimates asset retirement obligation	'	'	'	9,245	'	'	'
Gain or loss recognized from the sale of interest	'	'	'	$0	'	'	'

Allocation_of_Recorded_Value_o

Allocation of Recorded Value of Net Assets Acquired in Transaction (Detail) (USD $)	Dec. 31, 2013	Jun. 18, 2012
In Thousands, unless otherwise specified
Business Combinations [Abstract]	'	'
Proved oil and gas properties	$39,221	'
Unevaluated oil and gas properties	1,637	'
Asset retirement obligations	-14,460	'
Total fair value of net assets	$26,398	$26,398

Financial_Data_Related_to_Oil_

Financial Data Related to Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Accumulated DD&A:	'		'		'
Balance, beginning of year	($5,510,166)		'		'
Provision for DD&A	-350,574		-344,365		-280,020
Balance, end of year	-5,908,760		-5,510,166		'
Net proved oil and gas properties	1,895,357		1,734,300		'
Lease operating expenses	201,153		215,003		175,881
Transportation, processing and gathering expenses	42,172		21,782		8,958
Production taxes	15,029		10,015		9,380
Accretion expense	33,575		33,331		30,764
United States [Member]	'		'		'
Oil and gas properties, proved and unevaluated:	'		'		'
Balance, beginning of year	7,692,261		7,049,777		6,202,758
Costs incurred during the year (capitalized):	'		'		'
Acquisition costs, net of sales of unevaluated properties	70,903		102,807		270,354
Exploratory costs	297,113		81,458		84,199
Development costs	378,242	[1]	395,555	[1]	426,355	[1]
Salaries, general and administrative costs	32,815		25,318		24,430
Interest	46,860		37,656		42,033
Less: overhead reimbursements	-321		-310		-352
Total costs incurred during the year	825,612		642,484		847,019
Balance, end of year	8,517,873		7,692,261		7,049,777
Accumulated DD&A:	'		'		'
Balance, beginning of year	-5,510,166		-5,174,729		-4,804,949
Provision for DD&A	-346,827		-341,096		-276,480
Sale of proved properties	-51,767		5,659		-93,300
Balance, end of year	-5,908,760		-5,510,166		-5,174,729
Net proved oil and gas properties	2,609,113		2,182,095		1,875,048
DD&A per Mcfe	3.43		3.69		3.45
Lease operating expenses	201,153		215,003		175,881
Transportation, processing and gathering expenses	42,172		21,782		8,958
Production taxes	15,029		10,015		9,380
Accretion expense	33,575		33,331		30,764
Expensed costs - United States	291,929		280,131		224,983
Canada [Member]	'		'		'
Oil and gas properties, proved and unevaluated:	'		'		'
Balance, beginning of year	'		'		'
Costs incurred during the year (capitalized):	'		'		'
Acquisition costs	8,764		'		'
Exploratory costs	1,819		'		'
Total costs incurred during the year	10,583		'		'
Balance, end of year	$10,583		'		'
[1]	Includes capitalized asset retirement costs of $54,737, $95,293 and $96,386, respectively.

Financial_Data_Related_to_Oil_1

Financial Data Related to Oil and Gas Producing Activities (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Asset retirement costs included in development cost	$54,737	$95,293	$96,386

Net_Costs_Incurred_on_Unevalua

Net Costs Incurred on Unevaluated Properties (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Acquisition costs evaluated during the year	$30,271	$9,739	($2,397)
Exploration costs evaluated during the year	188,830	-1,209	-51,207
Capitalized interest costs evaluated during the year	46,860	37,656	42,033
Total costs incurred during the year, net of divestitures	$265,961	$46,186	($11,571)

Financial_Data_Associated_with

Financial Data Associated with Unevaluated Costs (Detail) (Unevaluated Costs [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Unevaluated Costs [Member]	'	'	'	'
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'	'	'
Acquisition costs	$306,793	'	'	'
Exploration costs	305,422	'	'	'
Capitalized interest	112,124	'	'	'
Total unevaluated costs	724,339	'	'	'
Acquisition costs	78,555	29,959	41,442	156,837
Exploration costs	248,846	56,033	499	44
Capitalized interest	39,846	32,755	20,501	19,022
Total unevaluated costs	$367,247	$118,747	$62,442	$175,903

Recovered_Sheet3

Investment in Oil and Gas Properties - Unaudited - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Project
Extractive Industries [Abstract]	'	'	'
Interest costs capitalized on unevaluated properties	$46,860	$37,656	$42,033
Specifically identified drilling projects	140	'	'
Projects expected to be evaluated	'4 years	'	'

Recovered_Sheet4

Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'	'
Maximum correlation between price of oil & natural gas in market and underlying price basis indicative in the derivative contract	100.00%	'
Accumulated other comprehensive income (loss)	($2,062)	$28,833

Location_and_Fair_Value_Amount

Location and Fair Value Amounts of Derivative Instruments Reported in Balance Sheet (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current liabilities [Member]	'	'
Liability Derivatives	'	'
Fair Value of Derivative Instruments, Liabilities	$7,753	'
Long-term liabilities [Member]	'	'
Liability Derivatives	'	'
Fair Value of Derivative Instruments, Liabilities	470	'
Current Asset [Member]	'	'
Asset Derivatives	'	'
Fair Value of Derivative Instruments, Assets	4,549	'
Long-term assets [Member]	'	'
Asset Derivatives	'	'
Fair Value of Derivative Instruments, Assets	1,378	'
Commodity Contracts [Member]	'	'
Asset Derivatives	'	'
Fair Value of Derivative Instruments, Assets	5,927	48,854
Liability Derivatives	'	'
Fair Value of Derivative Instruments, Liabilities	8,223	1,679
Commodity Contracts [Member] | Current liabilities [Member]	'	'
Liability Derivatives	'	'
Fair Value of Derivative Instruments, Liabilities	7,753	149
Commodity Contracts [Member] | Long-term liabilities [Member]	'	'
Liability Derivatives	'	'
Fair Value of Derivative Instruments, Liabilities	470	1,530
Commodity Contracts [Member] | Current Asset [Member]	'	'
Asset Derivatives	'	'
Fair Value of Derivative Instruments, Assets	4,549	39,655
Commodity Contracts [Member] | Long-term assets [Member]	'	'
Asset Derivatives	'	'
Fair Value of Derivative Instruments, Assets	$1,378	$9,199

Before_Tax_Effect_of_Derivativ

Before Tax Effect of Derivative Instruments in Statement of Operations (Detail) (Cash Flow Hedging [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion, Net, Total	($26,945)		$41,209		$43,089
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net, Total	20,289	[1]	30,326	[1]	-13,274	[1]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net, Total	-2,090		3,428		1,418
Commodity Contracts [Member]	'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion, Net, Total	-26,945		41,209		43,089
Derivative income (expense), net [Member]	'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net, Total	-2,090		3,428		1,418
Operating revenue - oil/gas production [Member]	'		'		'
Derivative Instruments, Gain (Loss) [Line Items]	'		'		'
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net, Total	$20,289	[1]	$30,326	[1]	($13,274)	[1]
[1]	For the year ended December 31, 2013, effective hedging contracts increased oil revenue by $3,520 and increased gas revenue by $16,769. For the year ended December 31, 2012, effective hedging contracts increased oil revenue by $8,546 and increased gas revenue by $21,780. For the year ended December 31, 2011, effective hedging contracts decreased oil revenue by $32,706 and increased gas revenue by $19,432.

Before_Tax_Effect_of_Derivativ1

Before Tax Effect of Derivative Instruments in Statement of Operations (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'	'	'
Decrease/increase in oil revenue owing to effective hedging contracts	$3,520	$8,546	$32,706
Decrease/increase in gas revenue owing to effective hedging contracts	$16,769	$21,780	$19,432

Impact_of_Rights_of_Offset_Ass

Impact of Rights of Offset Associated with Recognized Assets and Liabilities (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Current Asset [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Assets	$4,549
Long-term assets [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Assets	1,378
Current liabilities [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Liabilities	-7,753
Long-term liabilities [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Liabilities	-470
Effects of Netting [Member] | Current Asset [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Assets	-4,043
Effects of Netting [Member] | Long-term assets [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Assets	-274
Effects of Netting [Member] | Current liabilities [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Liabilities	4,043
Effects of Netting [Member] | Long-term liabilities [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Liabilities	274
With Effects of Netting [Member] | Current Asset [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Assets	506
With Effects of Netting [Member] | Long-term assets [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Assets	1,104
With Effects of Netting [Member] | Current liabilities [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Liabilities	-3,710
With Effects of Netting [Member] | Long-term liabilities [Member]	'
Derivative Instruments And Hedging Activities [Line Items]	'
Fair Value of Derivative Instruments, Liabilities	($196)

Hedging_Positions_Detail

Hedging Positions (Detail)	Dec. 31, 2013
	MMBTU
Natural Gas [Member] | 2014 Hedging Position One [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4
Natural Gas [Member] | 2014 Hedging Position Two [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.04
Natural Gas [Member] | 2014 Hedging Position Three [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.105
Natural Gas [Member] | 2014 Hedging Position Four [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.19
Natural Gas [Member] | 2014 Hedging Position Five [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000	[1]
Swap Price	4.25
Natural Gas [Member] | 2014 Hedging Position Six [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.25
Natural Gas [Member] | 2014 Hedging Position Seven [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.35
Natural Gas [Member] | 2015 Hedging Position One [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.005
Natural Gas [Member] | 2015 Hedging Position Two [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.12
Natural Gas [Member] | 2015 Hedging Position Three [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.15
Natural Gas [Member] | 2015 Hedging Position Four [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.165
Natural Gas [Member] | 2015 Hedging Position Five [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.22
Natural Gas [Member] | 2015 Hedging Position Six [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.255
Natural Gas [Member] | 2016 Hedging Position One [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.11
Natural Gas [Member] | 2016 Hedging Position Two [Member]	'
Derivative [Line Items]	'
Daily Volume	10,000
Swap Price	4.12
Oil [Member] | 2014 Hedging Position One [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	90.06
Oil [Member] | 2014 Hedging Position Two [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	92.25
Oil [Member] | 2014 Hedging Position Three [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	93.55
Oil [Member] | 2014 Hedging Position Four [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	94
Oil [Member] | 2014 Hedging Position Five [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	98
Oil [Member] | 2014 Hedging Position Six [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	98.3
Oil [Member] | 2014 Hedging Position Seven [Member]	'
Derivative [Line Items]	'
Daily Volume	2	[2]
Swap Price	98.85
Oil [Member] | 2014 Hedging Position Eight [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	99.65
Oil [Member] | 2014 Hedging Position Nine [Member]	'
Derivative [Line Items]	'
Daily Volume	1	[3]
Swap Price	103.3
Oil [Member] | 2015 Hedging Position One [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	89
Oil [Member] | 2015 Hedging Position Two [Member]	'
Derivative [Line Items]	'
Daily Volume	1
Swap Price	90
[1]	February through December
[2]	January through June
[3]	Brent crude oil contract

Assets_and_Liabilities_Measure

Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Marketable securities	$8,248	$13,492
Assets, Fair Value, Total	14,175	62,346
Liabilities, Fair Value, Total	8,223	1,679
Hedging contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Assets, Fair Value	5,927	48,854
Derivative Liabilities, Fair Value	8,223	1,679
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Marketable securities	8,248	13,492
Assets, Fair Value, Total	8,248	13,492
Liabilities, Fair Value, Total	'	'
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Hedging contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Assets, Fair Value	'	'
Derivative Liabilities, Fair Value	'	'
Significant Other Observable Inputs (Level 2) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Marketable securities	'	'
Assets, Fair Value, Total	5,927	48,854
Liabilities, Fair Value, Total	8,223	1,679
Significant Other Observable Inputs (Level 2) [Member] | Hedging contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Assets, Fair Value	5,927	48,854
Derivative Liabilities, Fair Value	8,223	1,679
Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Marketable securities	'	'
Assets, Fair Value, Total	'	'
Liabilities, Fair Value, Total	'	'
Significant Unobservable Inputs (Level 3) [Member] | Hedging contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative Assets, Fair Value	'	'
Derivative Liabilities, Fair Value	'	'

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	Dec. 31, 2013	Nov. 27, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
8.625 % Senior Notes Due 2017 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Long term debt, Fair Value	'	'	$401,250
Convertible Notes Due 2017 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Liability component of convertible note	260,377	'	249,601
7.5% Senior Notes due 2022 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Liability component of convertible note	814,719	'	314,250
Aggregate principal amount of senior notes	'	$475,000	'

Changes_in_Asset_Retirement_Ob

Changes in Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]	'	'	'
Asset retirement obligations as of the beginning of the year, including current portion	$488,302	$425,779	$373,920
Liabilities incurred	19,043	3,869	7,993
Liabilities settled	-79,695	-67,641	-63,226
Liabilities assumed	'	15,263	59,441
Divestment of properties	-9,245	-7,563	-10,900
Accretion expense	33,575	33,331	30,764
Revision of estimates	50,533	85,264	27,787
Asset retirement obligations as of the end of the year, including current portion	$502,513	$488,302	$425,779

Analysis_of_Deferred_Taxes_Det

Analysis of Deferred Taxes (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Tax effect of temporary differences:	'	'
Net operating loss carryforwards	$24,437	'
Oil and gas properties - full cost	-576,393	-465,862
Asset retirement obligations	180,905	175,788
Stock compensation	5,537	5,588
Hedges	826	-16,983
Accrued incentive compensation	9,189	4,762
Other	3,484	1,391
Deferred Tax Assets, Net, Total	($358,983)	($295,316)

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Current federal income tax benefit	($10,904)	$15,022	($20,386)
Current income tax receivable	7,366	10,027	'
Operating loss carryforwards	67,882	'	'
Operating loss carryforwards expiration year	'2033	'	'
Statutory depletion deductions available for tax reporting purposes	1,453	'	'
Income taxes allocated to other comprehensive income related to oil and gas hedges	-17,003	3,918	20,290
Unrecognized tax benefits, interest expense	$0	$385	'

Reconciliation_Between_Statuto

Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax Rate as Percentage of Income Before Income Taxes (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Income tax expense computed at the statutory federal income tax rate	35.00%	35.00%	35.00%
State taxes	1.00%	1.00%	1.00%
IRC Sec. 162(m) limitation	0.80%	0.60%	0.30%
Other	0.10%	-0.50%	-0.30%
Effective income tax rate	36.90%	36.10%	36.00%

Reconciliation_of_Total_Amount

Reconciliation of Total Amounts of Unrecognized Tax Benefits (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Total unrecognized tax benefits, beginning balance	$385
Tax positions taken during a prior period	'
Tax positions taken during the current period	'
Settlements with taxing authorities	-385
Lapse of applicable statute of limitations	'
Total unrecognized tax benefits, ending balance	'

LongTerm_Debt_Detail

Long-Term Debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'
Long-term debt	$1,027,084	$914,126
8.625% Senior Notes due 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	'	375,000
1.75% Senior Convertible Notes due 2017 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	252,084	239,126
7.5% Senior Notes due 2022 [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	775,000	300,000
Bank debt [Member]	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	'	'

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Feb. 25, 2014

Dec. 31, 2013

Dec. 31, 2012

Apr. 26, 2011

Dec. 31, 2013

Feb. 25, 2014

Dec. 31, 2013

Dec. 31, 2012

Mar. 06, 2012

Nov. 27, 2013

Nov. 08, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Nov. 17, 2010

Jan. 26, 2010

Letter of Credit[Member]

Letter of Credit[Member]

Bank debt [Member]

Bank debt [Member]

Bank debt [Member]

Bank Credit Facility[Member]

Bank Credit Facility[Member]

1.75% Senior Convertible Notes due 2017 [Member]

1.75% Senior Convertible Notes due 2017 [Member]

1.75% Senior Convertible Notes due 2017 [Member]

7.5% Senior Notes due 2022 [Member]

7.5% Senior Notes due 2022 [Member]

7.5% Senior Notes due 2022 [Member]

7.5% Senior Notes due 2022 [Member]

8.625% Senior Notes due 2017 [Member]

8.625% Senior Notes due 2017 [Member]

8.625% Senior Notes due 2017 [Member]

8.625% Senior Notes due 2017 [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Credit facility initial date

'

'

'

'

'

'

26-Apr-11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redetermined base borrowing and credit facility

'

'

'

'

'

'

'

'

$700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Maturity of new credit facility if note issue under 2004 indenture are retired on or before April 15, 2014

'

'

'

'

'

'

'

'

'

26-Apr-15

'

'

'

'

'

'

'

'

'

'

'

'

Initial bank and availability under facility

'

'

'

'

'

'

400,000

'

'

378,594

378,594

'

'

'

'

'

'

'

'

'

'

'

Outstanding borrowing under bank credit facility

'

'

'

'

21,406

21,406

'

'

'

0

0

'

'

'

'

'

'

'

'

'

'

'

Period in which outstanding amount has to be repaid to cure deficiency

'

'

'

'

'

'

'10 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Period in which bank has to add new properties to borrowing base and has to grant mortgage to banks

'

'

'

'

'

'

'30 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Oil and gas reserve as proportion of discounted present value of future net cash flow, for mortgage

'

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt to EBITDA ratio, as defined in credit agreement

'

'

'

'

'

'

'not greater than 3.25 for preceding four quarter

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

EBITDA to consolidated net interest, as defined in credit agreement

'

'

'

'

'

'

'not less than 3.0 for preceding four quarter

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt to EBITDA ratio

'

'

'

'

'

'

'1.73 to 1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

EBITDA to consolidated net interest ratio

'

'

'

'

'

'

'18.40 to 1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Aggregate principal amount of senior notes

'

'

'

'

'

'

'

'

'

'

'

'

300,000

300,000

475,000

300,000

'

'

'

'

100,000

275,000

Initial conversion rate of convertible note 2017

'

'

'

'

'

'

'

'

'

'

'

'An initial conversion rate of 23.4449 shares of our common stock per $1 principal amount of 2017 Convertible Notes

'

'

'

'

'

'

'

'

'

'

Initial conversion rate of common stock

'

'

'

'

'

'

'

'

'

'

'

23.4449

'

'

'

'

'

'

'

'

'

'

Principal amount of 2017 convertible notes

'

'

'

'

'

'

'

'

'

'

'

$1

'

'

'

'

'

'

'

'

'

'

Initial conversion price of convertible note 2017

'

'

'

'

'

'

'

'

'

'

'

$42.65

'

'

'

'

'

'

'

'

'

'

Closing share price

'

'

'

'

'

'

'

'

'

'

'

$34.59

'

'

'

'

'

'

'

'

'

'

Convertible notes principal amount

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

Percentage of current conversion price lower than closing sale price

'

'

'

'

'

'

'

'

'

'

'

130.00%

'

'

'

'

'

'

'

'

'

'

Maximum trading day

'

'

'

'

'

'

'

'

'

'

'

'20 days

'

'

'

'

'

'

'

'

'

'

Consecutive trading days ending on last trading day

'

'

'

'

'

'

'

'

'

'

'

'30 days

'

'

'

'

'

'

'

'

'

'

Period in which distribution is made to all holders of common stock rights, option or warrants

'

'

'

'

'

'

'

'

'

'

'

'45 days

'

'

'

'

'

'

'

'

'

'

Consecutive trading days immediately preceding, but excluding, declaration date

'

'

'

'

'

'

'

'

'

'

'

'10 days

'

'

'

'

'

'

'

'

'

'

Percentage in which distribution has per share value exceeding closing sale price of common stock

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

Percentage in which closing sale price of common stock is excess of convertible notes

'

'

'

'

'

'

'

'

'

'

'

98.00%

'

'

'

'

'

'

'

'

'

'

Number of consecutive business day

'

'

'

'

'

'

'

'

'

'

'

'5 days

'

'

'

'

'

'

'

'

'

'

Number of consecutive trading day

'

'

'

'

'

'

'

'

'

'

'

'25 days

'

'

'

'

'

'

'

'

'

'

Payment for call option

'

'

'

'

'

'

'

'

'

'

'

70,830

'

'

'

'

'

'

'

'

'

'

Anti-dilution adjustments for purchases of call option

'

'

'

'

'

'

'

'

'

'

'

7,033,470

'

'

'

'

'

'

'

'

'

'

Strike price per share

'

'

'

'

'

'

'

'

'

'

'

$55.91

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of warrants

'

'

'

'

'

'

'

'

'

'

'

40,170

'

'

'

'

'

'

'

'

'

'

Liability component of convertible note

1,027,084

1,027,084

914,126

'

'

'

'

'

'

'

'

252,084

239,126

'

'

'

775,000

300,000

'

375,000

'

'

Accrued interest payment

'

'

'

'

'

'

'

'

'

'

'

1,750

'

'

'

'

'

'

'

'

'

'

Interest cost related to amortization of discount

'

'

'

'

'

'

'

'

'

'

'

12,959

9,956

'

'

'

'

'

'

'

'

'

Amortization of deferred financing cost

'

'

'

'

'

'

'

'

'

'

'

1,238

951

'

'

'

'

'

'

'

'

'

Interest expense related to contractual interest coupon of convertible notes

'

'

'

'

'

'

'

'

'

'

'

5,250

4,302

'

'

'

'

'

'

'

'

'

Proceeds from issuance of senior notes

'

489,250

300,000

'

'

'

'

'

'

'

'

'

'

'

480,195

293,203

'

'

'

'

'

'

Effective interest rates

7.51%

7.51%

7.75%

7.04%

'

'

'

'

'

'

'

'

'

'

3.00%

'

'

'

'

'

'

'

Redemption of senior notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

Equity offerings redemption price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

107.50%

'

'

'

'

'

'

Accrued interest payment

9,022

9,022

18,546

'

'

'

'

'

'

'

'

'

'

'

'

'

7,266

'

'

'

'

'

Total cost of the redemption

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

406,967

'

'

'

Cost of redemption excluding accrued and unpaid interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

396,014

'

'

'

Accrued and unpaid interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,953

'

'

'

Redemption resulted in a charge to earnings

-27,279

-27,279

-1,972

-607

'

'

'

'

'

'

'

'

'

'

'

'

'

'

27,279

'

'

'

Premium paid for the repurchase and redemption

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

21,014

'

'

'

Deferred financing costs write off

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,265

'

'

'

Deferred financing costs, net of accumulated amortization

11,754

11,754

27,753

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total interest cost incurred

'

$79,697

$68,031

$51,322

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Schedule_of_Changes_In_Accumul

Schedule of Changes In Accumulated Other Comprehensive Income Loss (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance, net of tax	$28,833	'	'
Other comprehensive income (loss) before reclassifications:	'	'	'
Change in fair value of derivatives	-26,945	'	'
Foreign currency translations	-667	'	'
Income tax effect	9,701	'	'
Net of tax	-17,911	'	'
Amounts reclassified from accumulated other comprehensive income:	'	'	'
Net of tax	12,984	'	'
Other comprehensive income (loss), net of tax	-30,895	'	'
Ending balance, net of tax	-2,062	'	'
Cash Flow Hedges [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance, net of tax	28,833	21,868	-14,204
Other comprehensive income (loss) before reclassifications:	'	'	'
Change in fair value of derivatives	-26,945	41,209	43,089
Income tax effect	9,701	-14,836	-15,512
Net of tax	-17,244	26,373	27,577
Amounts reclassified from accumulated other comprehensive income:	'	'	'
Net of tax	12,984	19,408	-8,495
Other comprehensive income (loss), net of tax	-30,228	6,965	36,072
Ending balance, net of tax	-1,395	28,833	21,868
Foreign Currency Items [Member]	'	'	'
Accumulated Other Comprehensive Income (Loss) [Line Items]	'	'	'
Beginning balance, net of tax	'	'	'
Other comprehensive income (loss) before reclassifications:	'	'	'
Change in fair value of derivatives	'	'	'
Foreign currency translations	-667	'	'
Income tax effect	'	'	'
Net of tax	-667	'	'
Amounts reclassified from accumulated other comprehensive income:	'	'	'
Net of tax	'	'	'
Other comprehensive income (loss), net of tax	-667	'	'
Ending balance, net of tax	-667	'	'
Reclassification out of Accumulated Other Comprehensive Income [Member]	'	'	'
Amounts reclassified from accumulated other comprehensive income:	'	'	'
Operating revenue: oil/gas production	20,289	'	'
Income tax effect	-7,305	'	'
Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]	'	'	'
Amounts reclassified from accumulated other comprehensive income:	'	'	'
Operating revenue: oil/gas production	20,289	30,326	-13,274
Income tax effect	-7,305	-10,918	4,779
Reclassification out of Accumulated Other Comprehensive Income [Member] | Foreign Currency Items [Member]	'	'	'
Amounts reclassified from accumulated other comprehensive income:	'	'	'
Operating revenue: oil/gas production	'	'	'
Income tax effect	'	'	'

Share_Based_Compensation_Addit

Share Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock based compensation	$15,425	$13,399	$8,914
Stock based compensation capitalized into oil and gas properties	5,078	4,288	3,010
Exercise price of stock options outstanding, minimum	$6.97	'	'
Exercise price of stock options outstanding, maximum	$53.20	'	'
Restricted stocks issued, shares	848,498	670,818	597,062
Restricted stocks issued, value	17,487,000	21,085,000	14,100,000
Unrecognized compensation cost, weighted average period of recognition	'1 year 8 months 12 days	'	'
Unrecognized compensation cost	17,004,000	'	'
Adjustments to additional paid-in capital related to net tax effect of stock options exercises and restricted stock vesting	-884,000	814,000	735,000
Restricted Stock[Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock based compensation	15,405	13,308	8,796
Restricted Stock[Member] | Minimum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period of stock options	'1 year	'	'
Restricted Stock[Member] | Maximum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period of stock options	'3 years	'	'
Stock Options[Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock based compensation	$20	$91	$118
2009 plan [Member] | All Employee [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period of stock options	'5 years	'	'
Period after which stock option will expire subsequent to award	'10 years	'	'
2009 plan [Member] | Non - Employee Directors [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period of stock options	'3 years	'	'
Period after which stock option will expire subsequent to award	'10 years	'	'

Summary_of_Stock_Option_Activi

Summary of Stock Option Activity under Plan (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Options outstanding	'	'	'
Options outstanding, beginning of period	411,794	438,394	484,694
Granted	'	'	'
Exercised	'	'	'
Forfeited	-15,250	-4,200	-13,300
Expired	-65,370	-22,400	-33,000
Options outstanding, end of period	331,174	411,794	438,394
Options exercisable, end of period	318,279	378,004	378,710
Options unvested, end of period	12,895	33,790	59,684
Options outstanding, weighted Average Exercise Price	'	'	'
Options outstanding, beginning of period	$39.04	$38.76	$39.43
Granted	'	'	'
Exercised	'	'	'
Forfeited	$42.45	$35.54	$37.98
Expired	$36.56	$34.25	$48.85
Options outstanding, end of period	$39.37	$39.04	$38.76
Options exercisable, end of period	$40.62	$41	$41.66
Options unvested, end of period	$8.64	$17.17	$20.36
Options outstanding	'	'	'
Options outstanding, end of period	'2 years 2 months 12 days	'2 years 9 months 18 days	'3 years 7 months 6 days
Options exercisable, end of period	'2 years 1 month 6 days	'2 years 6 months	'3 years 1 month 6 days
Options unvested, end of period	'5 years	'5 years 4 months 24 days	'6 years 1 month 6 days
Options outstanding, end of period, aggregate intrinsic value	'	'	'
Options outstanding, end of period	$1,708	$766	$1,143
Options exercisable, end of period	1,373	459	457
Options unvested, end of period	$335	$307	$686

Summary_of_Restricted_Stock_Ac

Summary of Restricted Stock Activity under Plan (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Number of restricted shares	'	'	'
Restricted stock outstanding, beginning of period	1,108,874	923,740	783,606
Issuances	848,498	670,818	597,062
Lapse of restrictions	-534,041	-462,141	-419,543
Forfeitures	-165,278	-23,543	-37,385
Restricted stock outstanding, end of period	1,258,053	1,108,874	923,740
Weighted average fair value	'	'	'
Restricted stock outstanding, beginning of period	$27.56	$20.08	$17.24
Issuances	$20.61	$31.43	$23.62
Lapse of restrictions	$25.45	$18.29	$19.91
Forfeitures	$26.43	$26.10	$18.92
Restricted stock outstanding, end of period	$23.92	$27.56	$20.08

Share_Repurchase_Program_Addit

Share Repurchase Program - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Sep. 24, 2007
Text Block [Abstract]	'	'
Stock repurchase program authorized aggregate amount	'	$100,000
Stock repurchase program total cost	$7,071	'
Stock repurchase program average price	$23.57	'
Share repurchased under share repurchase program	300,000	'

Recovered_Sheet5

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBbls
Commitments And Contingencies Disclosure [Abstract]	'	'	'
Lease of facilities, maturity year	'2018	'	'
Payments related to lease obligations	$597	$894	$446
Contingent liability to surety insurance company	81,878	'	'
Commitments to use drilling rigs and acquisition of seismic data, value	216,726	'	'
Commitments to use drilling rigs and acquisition of seismic data, period	'4 years	'	'
Deposit to guarantee commitments	22,350	'	'
Minimum barrels of oil spill to impose financial responsibility under Oil Pollution Act	1,000	'	'
Minimum financial responsibility in amounts if oil spill exceeds minimum quantity of barrels of oil in specified state	10,000	'	'
Minimum financial responsibility in amounts if oil spill exceeds minimum quantity of barrels of oil Outer Continental	35,000	'	'
Maximum financial responsibility in amounts if oil spill exceeds minimum quantity of barrels of oil	150,000	'	'
Approximate asserted claims plus accrued interest assessed by Louisiana Department of Revenue	$13,000	'	'

Minimum_Net_Annual_Commitments

Minimum Net Annual Commitments Under all Leases, Subleases and Contracts with Non-Cancelable Terms in Excess of 12 Months (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Operating Leases Future Minimum Payments Due [Abstract]	'
2014	$736
2015	637
2016	358
2017	301
2018	$147

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)

12 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2013

20-May-11

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Minimum [Member]

Maximum [Member]

2009 plan [Member]

2009 plan [Member]

2009 plan [Member]

2009 plan [Member]

Restricted Stock Grants [Member]

Restricted Stock Grants [Member]

All Employee [Member]

Non - Employee Directors [Member]

Minimum [Member]

Maximum [Member]

Employee Benefit And Retirement Plans [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Liability of vested benefits recorded in other long term liabilities

$1,062

'

'

'

'

'

'

'

'

'

'

'

Expenses related to incentive compensation bonus

15,340

8,113

11,600

'

'

'

'

'

'

'

'

'

Additional number of common stock to be issued under incentive stock options

'

'

'

'

'

'

'

2,800,000

'

'

'

'

Vesting period of stock options

'

'

'

'

'

'

'

'

'5 years

'3 years

'1 year

'3 years

Period after which stock option will expire subsequent to award

'

'

'

'

'

'

'

'

'10 years

'10 years

'

'

Additional shares available for issuance

'

'

'

'

'

'

2,081,866

'

'

'

'

'

Percentage of vesting of an employee in matching contributions for each year of service

20.00%

'

'

'

'

'

'

'

'

'

'

'

Number of years required for vesting of contribution

'5 years

'

'

'

'

'

'

'

'

'

'

'

Amount of contribution by the company to Stone Energy 401 (k) Profit Sharing Plan

1,793

1,759

1,435

'

'

'

'

'

'

'

'

'

Maximum Percentage of Deferred Compensation plan

100.00%

'

'

'

'

'

'

'

'

'

'

'

Plan assets included in other assets

8,248

7,498

'

'

'

'

'

'

'

'

'

'

Number of times of severance payments relating to annual pay and any target bonus at one hundred percent level

2.99

'

'

'

'

'

'

'

'

'

'

'

Percentage of excise tax rate under Section 4999 of the Internal revenue code

20.00%

'

'

'

'

'

'

'

'

'

'

'

Percentage of employer matching contribution under 401(k) plan

50.00%

'

'

'

'

'

'

'

'

'

'

'

Amount of one week's pay of each full of annual pay under Employee severance Plan

'

'

'

$10,000

'

'

'

'

'

'

'

'

Maximum period of sum of payments and benefits under employee severance plan

'

'

'

'

'84 days

'12 months

'

'

'

'

'

'

Period of involuntary termination of employment

'

'

'

'6 months

'

'

'

'

'

'

'

'

Oil_Gas_Reserve_Information_Ad

Oil Gas Reserve Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf	MMcf	MMcf
Reserve Quantities [Line Items]	'	'	'
Adoption of assumption due to revision of oil and gas reporting requirements	'Using a historical 12-month average pricing assumption	'	'
Average 12-month oil prices net of differentials	102.21	101.2	100.97
Average 12-month gas prices net of differentials	3.66	2.68	4.74
Annual discount rate for discounting future cash flows	10.00%	'	'
Pyrenees project [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Acquisition of additional working interested in pyrenees project	'	'	15.00%
Purchase of producing properties	'	'	6
Pompano and Mica fields [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Purchase of producing properties	'	'	102
Appalachia drilling program [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions, discoveries and other additions	117	162	94
Deep gas development project at LaCantera [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions, discoveries and other additions	'	17	11
GOM drilling program at Mississippi Canyon Block 109 [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions, discoveries and other additions	'	'	6
Sale of our non-operated interest in the Main Pass Block 296 and 311 fields [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Sale of reserves	'	'	13
Positive reserve report pricing changes [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	17.8	'	'
Well performance [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	54.5	'	'
Natural Gas Liquids (MBbls) [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions, discoveries and other additions	4,395	4,856	'
Revisions of previous estimates	2,439	9,349	4,911
Purchase of producing properties	'	619	'
Average 12-month gas prices net of differentials	37.59	38.23	58.26

Summary_of_Estimated_Proved_Oi

Summary of Estimated Proved Oil and Natural Gas Reserve (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBbls	MBbls	MBbls
Oil (MBbls) [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated proved reserves, beginning balance	44,918	45,655	33,203
Revisions of previous estimates	3,606	-1,559	2,889
Extensions, discoveries and other additions	2,367	3,681	3,544
Purchase of producing properties	'	4,336	14,396
Sale of reserves	-170	-60	-1,950
Production	-6,894	-7,135	-6,427
Estimated proved reserves, ending balance	43,827	44,918	45,655
Estimated proved developed reserves	27,920	29,005	30,914
Natural Gas Liquids (MBbls) [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated proved reserves, beginning balance	18,066	4,405	'
Revisions of previous estimates	2,439	9,349	4,911
Extensions, discoveries and other additions	4,395	4,856	'
Purchase of producing properties	'	619	'
Production	-1,603	-1,163	-506
Estimated proved reserves, ending balance	23,297	18,066	4,405
Estimated proved developed reserves	11,569	8,593	3,195
Natural Gas (MMcf) [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated proved reserves, beginning balance	395,374	325,479	274,705
Revisions of previous estimates	36,006	-26,694	-26,725
Extensions, discoveries and other additions	79,729	131,408	93,520
Purchase of producing properties	'	8,168	24,595
Sale of reserves	-214	-418	-2,150
Production	-50,129	-42,569	-38,466
Estimated proved reserves, ending balance	460,766	395,374	325,479
Estimated proved developed reserves	246,946	210,956	171,871
Oil And Natural Gas (MMcfe) [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Estimated proved reserves, beginning balance	773,285	625,839	473,923
Revisions of previous estimates	72,275	20,050	20,075
Extensions, discoveries and other additions	120,299	182,633	114,784
Purchase of producing properties	'	37,895	110,971
Sale of reserves	-1,235	-775	-13,850
Production	-101,111	-92,357	-80,064
Estimated proved reserves, ending balance	863,513	773,285	625,839
Estimated proved developed reserves	483,885	436,540	376,528

Summary_of_Standardized_Measur

Summary of Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Future cash inflows	$7,040,928	$6,295,455	$6,171,279
Future production costs	-2,062,657	-1,946,426	-1,747,806
Future development costs	-1,431,101	-1,241,531	-1,219,214
Future income taxes	-884,637	-799,007	-852,364
Future net cash flows	2,662,533	2,308,491	2,351,895
10% annual discount	-977,531	-794,632	-808,933
Standardized measure of discounted future net cash flows	1,685,002	1,513,859	1,542,962
Changes in standardized measure of future net cash flows related to estimated proved oil and gas reserves	'	'	'
Standardized measure at beginning of year	1,513,859	1,542,962	957,629
Sales and transfers of oil, gas and NGLs produced, net of production costs	-708,017	-697,741	-670,347
Changes in price, net of future production costs	229,425	-380,841	502,324
Extensions and discoveries, net of future production and development costs	155,592	178,272	293,168
Changes in estimated future development costs, net of development costs incurred during the period	28,684	212,329	97,852
Revisions of quantity estimates	281,558	76,450	-27,854
Accretion of discount	202,087	207,292	118,722
Net change in income taxes	-28,084	22,947	-300,363
Purchases of reserves in-place	'	276,389	567,286
Sales of reserves in-place	15,531	2,480	-36,278
Changes in production rates due to timing and other	-5,633	73,320	40,823
Net increase (decrease) in standardized measure	171,143	-29,103	585,333
Standardized measure at end of year	$1,685,002	$1,513,859	$1,542,962

Results_of_Operations_by_Quart

Results of Operations by Quarter (Detail) (USD $)	3 Months Ended									12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'		'	'	'	'	'	'	'	'	'	'
Operating revenue	$239,253		$256,685	$245,877	$233,732	$254,871	$227,397	$226,561	$244,957	$974,179	$951,489	$869,921
Income from operations	37,206	[1]	62,422	69,525	72,828	78,397	44,485	56,156	84,927	241,981	263,965	311,000
Net income	$1,752	[1],[2]	$36,102	$39,022	$40,758	$44,246	$23,659	$30,547	$50,974	$117,634	$149,426	$194,332
Basic earnings per share	$0.04		$0.72	$0.78	$0.82	$0.89	$0.48	$0.62	$1.04	$2.36	$3.03	$3.97
Diluted earnings per share	$0.04		$0.72	$0.78	$0.82	$0.89	$0.48	$0.62	$1.04	$2.36	$3.03	$3.97
[1]	Includes franchise tax settlement of $12,590 before income tax effect ($8,058, net of income tax effect).
[2]	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

Results_of_Operations_by_Quart1

Results of Operations by Quarter (Parenthetical) (Detail) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'
Franchise tax settlement	$12,590	$12,590	'	'
Franchise tax settlement, after tax	8,058	'	'	'
Loss on early extinguishment of debt, before tax	27,279	27,279	1,972	607
Loss on early extinguishment of debt, after tax	$17,459	'	'	'

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (Subsequent Event [Member], USD $)	0 Months Ended
In Thousands, unless otherwise specified	Jan. 16, 2014	Jan. 31, 2014
	Cut Off and Clovelly Fields [Member]	Hatch Point Field [Member]
Subsequent Event [Line Items]	'	'
Cash consideration received on sale of interest	$41,575	$9,720

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheet (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Current assets:	'		'		'	'
Cash and cash equivalents	$331,224		$279,526		$38,451	$106,956
Accounts receivable	171,971		167,288		'	'
Fair value of hedging contracts	4,549		39,655		'	'
Current income tax receivable	7,366		10,027		'	'
Deferred taxes	31,710	[1]	15,514	[1]	'	'
Inventory	3,723		4,207		'	'
Other current assets	1,874		3,626		'	'
Total current assets	552,417		519,843		'	'
Oil and gas properties, full cost method:	'		'		'	'
Proved	7,804,117		7,244,466		'	'
Less: accumulated DD&A	-5,908,760		-5,510,166		'	'
Net proved oil and gas properties	1,895,357		1,734,300		'	'
Unevaluated	724,339		447,795		'	'
Other property and equipment, net	26,178		22,115		'	'
Fair value of hedging contracts	1,378		9,199		'	'
Other assets, net	48,887		43,179		'	'
Total assets	3,248,556		2,776,431		'	'
Current liabilities:	'		'		'	'
Accounts payable to vendors	195,677		94,361		'	'
Undistributed oil and gas proceeds	37,029		23,414		'	'
Accrued interest	9,022		18,546		'	'
Fair value of hedging contracts	7,753		149		'	'
Asset retirement obligations	67,161		66,260		'	'
Other current liabilities	54,520		16,765		'	'
Total current liabilities	371,162		219,495		'	'
Long-term debt	1,027,084		914,126		'	'
Deferred taxes	390,693	[1]	310,830	[1]	'	'
Asset retirement obligations	435,352		422,042		'	'
Fair value of hedging contracts	470		1,530		'	'
Other long-term liabilities	53,509		36,275		'	'
Total liabilities	2,278,270		1,904,298		'	'
Commitments and contingencies	'		'		'	'
Stockholders' equity:	'		'		'	'
Common stock	488		484		'	'
Treasury stock	-860		-860		'	'
Additional paid-in capital	1,397,885		1,386,475		'	'
Accumulated deficit	-425,165		-542,799		'	'
Accumulated other comprehensive income	-2,062		28,833		'	'
Total stockholders' equity	970,286		872,133		667,829	430,357
Total liabilities and stockholders' equity	3,248,556		2,776,431		'	'
Parent [Member]	'		'		'	'
Current assets:	'		'		'	'
Cash and cash equivalents	246,294		228,398		37,389	105,115
Accounts receivable	74,887		59,213		'	'
Current income tax receivable	7,366		10,027		'	'
Deferred taxes	8,659	[1]	5,947	[1]	'	'
Inventory	3,440		3,924		'	'
Other current assets	1,874		3,626		'	'
Total current assets	342,520		311,135		'	'
Oil and gas properties, full cost method:	'		'		'	'
Proved	1,309,527		1,004,808		'	'
Less: accumulated DD&A	-459,932		-370,111		'	'
Net proved oil and gas properties	849,595		634,697		'	'
Unevaluated	325,113		254,757		'	'
Other property and equipment, net	26,178		22,115		'	'
Other assets, net	45,410		41,679		'	'
Investment in subsidiary	747,472		736,331		'	'
Total assets	2,336,288		2,000,714		'	'
Current liabilities:	'		'		'	'
Accounts payable to vendors	173,147		74,503		'	'
Undistributed oil and gas proceeds	34,386		21,841		'	'
Accrued interest	9,022		18,546		'	'
Other current liabilities	53,682		16,765		'	'
Total current liabilities	270,237		131,655		'	'
Long-term debt	1,027,084		914,126		'	'
Deferred taxes	10,227	[1]	47,758	[1]	'	'
Asset retirement obligations	4,945		5,479		'	'
Other long-term liabilities	53,509		29,563		'	'
Total liabilities	1,366,002		1,128,581		'	'
Commitments and contingencies	'		'		'	'
Stockholders' equity:	'		'		'	'
Common stock	488		484		'	'
Treasury stock	-860		-860		'	'
Additional paid-in capital	1,397,885		1,386,475		'	'
Accumulated deficit	-425,165		-542,799		'	'
Accumulated other comprehensive income	-2,062		28,833		'	'
Total stockholders' equity	970,286		872,133		'	'
Total liabilities and stockholders' equity	2,336,288		2,000,714		'	'
Guarantor Subsidiary [Member]	'		'		'	'
Current assets:	'		'		'	'
Cash and cash equivalents	84,290		51,128		926	1,659
Accounts receivable	97,128		108,075		'	'
Fair value of hedging contracts	4,549		39,655		'	'
Deferred taxes	23,051	[1]	9,567	[1]	'	'
Inventory	283		283		'	'
Total current assets	209,301		208,708		'	'
Oil and gas properties, full cost method:	'		'		'	'
Proved	6,494,590		6,239,658		'	'
Less: accumulated DD&A	-5,448,828		-5,140,055		'	'
Net proved oil and gas properties	1,045,762		1,099,603		'	'
Unevaluated	388,643		193,038		'	'
Fair value of hedging contracts	1,378		9,199		'	'
Other assets, net	1,349		1,500		'	'
Total assets	1,646,433		1,512,048		'	'
Current liabilities:	'		'		'	'
Accounts payable to vendors	22,530		19,858		'	'
Undistributed oil and gas proceeds	2,643		1,573		'	'
Fair value of hedging contracts	7,753		149		'	'
Asset retirement obligations	67,161		66,260		'	'
Other current liabilities	838		'		'	'
Total current liabilities	100,925		87,840		'	'
Deferred taxes	380,466	[1]	263,072	[1]	'	'
Asset retirement obligations	430,407		416,563		'	'
Fair value of hedging contracts	470		1,530		'	'
Other long-term liabilities	'		6,712		'	'
Total liabilities	912,268		775,717		'	'
Commitments and contingencies	'		'		'	'
Stockholders' equity:	'		'		'	'
Additional paid-in capital	1,309,563		1,496,510		'	'
Accumulated deficit	-574,003		-789,012		'	'
Accumulated other comprehensive income	-1,395		28,833		'	'
Total stockholders' equity	734,165		736,331		'	'
Total liabilities and stockholders' equity	1,646,433		1,512,048		'	'
Non-Guarantor Subsidiaries [Member]	'		'		'	'
Current assets:	'		'		'	'
Cash and cash equivalents	640		'		136	182
Total current assets	640		'		'	'
Oil and gas properties, full cost method:	'		'		'	'
Unevaluated	10,583		'		'	'
Other assets, net	2,128		'		'	'
Investment in subsidiary	12,711		'		'	'
Total assets	26,062		'		'	'
Current liabilities:	'		'		'	'
Accounts payable to vendors	44		'		'	'
Total current liabilities	44		'		'	'
Total liabilities	44		'		'	'
Commitments and contingencies	'		'		'	'
Stockholders' equity:	'		'		'	'
Additional paid-in capital	27,403		'		'	'
Accumulated deficit	-52		'		'	'
Accumulated other comprehensive income	-1,333		'		'	'
Total stockholders' equity	26,018		'		'	'
Total liabilities and stockholders' equity	26,062		'		'	'
Consolidation, Eliminations [Member]	'		'		'	'
Current assets:	'		'		'	'
Accounts receivable	-44		'		'	'
Total current assets	-44		'		'	'
Oil and gas properties, full cost method:	'		'		'	'
Investment in subsidiary	-760,183		-736,331		'	'
Total assets	-760,227		-736,331		'	'
Current liabilities:	'		'		'	'
Accounts payable to vendors	-44		'		'	'
Total current liabilities	-44		'		'	'
Total liabilities	-44		'		'	'
Commitments and contingencies	'		'		'	'
Stockholders' equity:	'		'		'	'
Additional paid-in capital	-1,336,966		-1,496,510		'	'
Accumulated deficit	574,055		789,012		'	'
Accumulated other comprehensive income	2,728		-28,833		'	'
Total stockholders' equity	-760,183		-736,331		'	'
Total liabilities and stockholders' equity	($760,227)		($736,331)		'	'
[1]	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.

Condensed_Consolidating_Statem

Condensed Consolidating Statement of Income (Detail) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Operating revenue:

'

'

'

'

'

'

'

'

'

'

'

Oil production

'

'

'

'

'

'

'

'

$715,104

$761,304

$663,958

Gas production

'

'

'

'

'

'

'

'

190,580

134,739

170,611

Natural gas liquids production

'

'

'

'

'

'

'

'

60,687

48,498

29,996

Other operational income

'

'

'

'

'

'

'

'

7,808

3,520

3,938

Derivative income, net

'

'

'

'

'

'

'

'

'

3,428

1,418

Total operating revenue

239,253

256,685

245,877

233,732

254,871

227,397

226,561

244,957

974,179

951,489

869,921

Operating expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

201,153

215,003

175,881

Transportation, processing and gathering expenses

'

'

'

'

'

'

'

'

42,172

21,782

8,958

Production taxes

'

'

'

'

'

'

'

'

15,029

10,015

9,380

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

350,574

344,365

280,020

Accretion expense

'

'

'

'

'

'

'

'

33,575

33,331

30,764

Salaries, general and administrative

'

'

'

'

'

'

'

'

59,524

54,648

40,169

Franchise tax settlement

12,590

'

'

'

'

'

'

'

12,590

'

'

Incentive compensation expense

'

'

'

'

'

'

'

'

15,340

8,113

11,600

Other operational expenses

'

'

'

'

'

'

'

'

151

267

2,149

Derivative expense, net

'

'

'

'

'

'

'

'

2,090

'

'

Total operating expenses

'

'

'

'

'

'

'

'

732,198

687,524

558,921

Income (loss) from operations

37,206

[1]

62,422

69,525

72,828

78,397

44,485

56,156

84,927

241,981

263,965

311,000

Other (income) expenses:

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

32,837

30,375

9,289

Interest income

'

'

'

'

'

'

'

'

-1,695

-600

-420

Other income

'

'

'

'

'

'

'

'

-2,799

-1,805

-1,942

Loss on early extinguishment of debt

27,279

'

'

'

'

'

'

'

27,279

1,972

607

Total other (income) expenses

'

'

'

'

'

'

'

'

55,622

29,942

7,534

Income (loss) before taxes

'

'

'

'

'

'

'

'

186,359

234,023

303,466

Provision (benefit) for income taxes:

'

'

'

'

'

'

'

'

'

'

'

Current

'

'

'

'

'

'

'

'

-10,904

15,022

-20,386

Deferred

'

'

'

'

'

'

'

'

79,629

69,575

129,520

Total income taxes

'

'

'

'

'

'

'

'

68,725

84,597

109,134

Net income (loss)

1,752

[1],[2]

36,102

39,022

40,758

44,246

23,659

30,547

50,974

117,634

149,426

194,332

Comprehensive income (loss)

'

'

'

'

'

'

'

'

86,739

156,391

230,404

Parent [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating revenue:

'

'

'

'

'

'

'

'

'

'

'

Oil production

'

'

'

'

'

'

'

'

30,475

26,149

5,675

Gas production

'

'

'

'

'

'

'

'

68,895

34,331

19,470

Natural gas liquids production

'

'

'

'

'

'

'

'

32,293

15,264

'

Other operational income

'

'

'

'

'

'

'

'

7,163

2,766

3,085

Total operating revenue

'

'

'

'

'

'

'

'

138,826

78,510

28,230

Operating expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

14,680

19,914

6,632

Transportation, processing and gathering expenses

'

'

'

'

'

'

'

'

28,322

12,049

'

Production taxes

'

'

'

'

'

'

'

'

6,229

3,330

1,434

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

93,579

63,022

17,860

Accretion expense

'

'

'

'

'

'

'

'

372

561

15

Salaries, general and administrative

'

'

'

'

'

'

'

'

59,473

54,641

40,073

Franchise tax settlement

'

'

'

'

'

'

'

'

12,590

'

'

Incentive compensation expense

'

'

'

'

'

'

'

'

15,340

8,113

11,600

Other operational expenses

'

'

'

'

'

'

'

'

38

173

1,404

Total operating expenses

'

'

'

'

'

'

'

'

230,623

161,803

79,018

Income (loss) from operations

'

'

'

'

'

'

'

'

-91,797

-83,293

-50,788

Other (income) expenses:

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

32,816

30,446

9,043

Interest income

'

'

'

'

'

'

'

'

-1,480

-285

-178

Other income

'

'

'

'

'

'

'

'

-875

-144

-52

Loss on early extinguishment of debt

'

'

'

'

'

'

'

'

27,279

1,972

607

(Income) loss from investment in subsidiaries

'

'

'

'

'

'

'

'

-214,983

-223,555

-232,751

Total other (income) expenses

'

'

'

'

'

'

'

'

-157,243

-191,566

-223,331

Income (loss) before taxes

'

'

'

'

'

'

'

'

65,446

108,273

172,543

Provision (benefit) for income taxes:

'

'

'

'

'

'

'

'

'

'

'

Current

'

'

'

'

'

'

'

'

-10,904

15,022

-20,386

Deferred

'

'

'

'

'

'

'

'

-41,284

-56,175

-1,403

Total income taxes

'

'

'

'

'

'

'

'

-52,188

-41,153

-21,789

Net income (loss)

'

'

'

'

'

'

'

'

117,634

149,426

194,332

Comprehensive income (loss)

'

'

'

'

'

'

'

'

86,739

156,391

230,404

Guarantor Subsidiary [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating revenue:

'

'

'

'

'

'

'

'

'

'

'

Oil production

'

'

'

'

'

'

'

'

684,629

735,155

658,283

Gas production

'

'

'

'

'

'

'

'

121,685

100,408

151,141

Natural gas liquids production

'

'

'

'

'

'

'

'

28,394

33,234

29,996

Other operational income

'

'

'

'

'

'

'

'

645

397

249

Derivative income, net

'

'

'

'

'

'

'

'

'

3,428

1,418

Total operating revenue

'

'

'

'

'

'

'

'

835,353

872,622

841,087

Operating expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

186,473

195,105

169,018

Transportation, processing and gathering expenses

'

'

'

'

'

'

'

'

13,850

9,733

8,958

Production taxes

'

'

'

'

'

'

'

'

8,800

6,685

7,946

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

256,995

281,152

261,326

Accretion expense

'

'

'

'

'

'

'

'

33,203

32,513

30,385

Salaries, general and administrative

'

'

'

'

'

'

'

'

5

7

94

Other operational expenses

'

'

'

'

'

'

'

'

113

94

745

Derivative expense, net

'

'

'

'

'

'

'

'

2,090

'

'

Total operating expenses

'

'

'

'

'

'

'

'

501,529

525,289

478,472

Income (loss) from operations

'

'

'

'

'

'

'

'

333,824

347,333

362,615

Other (income) expenses:

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

21

-71

246

Interest income

'

'

'

'

'

'

'

'

-195

-315

-242

Other income

'

'

'

'

'

'

'

'

-1,924

-1,661

-1,890

(Income) loss from investment in subsidiaries

'

'

'

'

'

'

'

'

'

75

827

Total other (income) expenses

'

'

'

'

'

'

'

'

-2,098

-1,972

-1,059

Income (loss) before taxes

'

'

'

'

'

'

'

'

335,922

349,305

363,674

Provision (benefit) for income taxes:

'

'

'

'

'

'

'

'

'

'

'

Deferred

'

'

'

'

'

'

'

'

120,913

125,750

130,923

Total income taxes

'

'

'

'

'

'

'

'

120,913

125,750

130,923

Net income (loss)

'

'

'

'

'

'

'

'

215,009

223,555

232,751

Comprehensive income (loss)

'

'

'

'

'

'

'

'

215,009

223,555

232,751

Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating revenue:

'

'

'

'

'

'

'

'

'

'

'

Other operational income

'

'

'

'

'

'

'

'

'

357

604

Total operating revenue

'

'

'

'

'

'

'

'

'

357

604

Operating expenses:

'

'

'

'

'

'

'

'

'

'

'

Lease operating expenses

'

'

'

'

'

'

'

'

'

-16

231

Depreciation, depletion, amortization

'

'

'

'

'

'

'

'

'

191

834

Accretion expense

'

'

'

'

'

'

'

'

'

257

364

Salaries, general and administrative

'

'

'

'

'

'

'

'

46

'

2

Total operating expenses

'

'

'

'

'

'

'

'

46

432

1,431

Income (loss) from operations

'

'

'

'

'

'

'

'

-46

-75

-827

Other (income) expenses:

'

'

'

'

'

'

'

'

'

'

'

Interest income

'

'

'

'

'

'

'

'

-20

'

'

(Income) loss from investment in subsidiaries

'

'

'

'

'

'

'

'

26

'

'

Total other (income) expenses

'

'

'

'

'

'

'

'

6

'

'

Income (loss) before taxes

'

'

'

'

'

'

'

'

-52

-75

-827

Provision (benefit) for income taxes:

'

'

'

'

'

'

'

'

'

'

'

Net income (loss)

'

'

'

'

'

'

'

'

-52

-75

-827

Comprehensive income (loss)

'

'

'

'

'

'

'

'

-52

-75

-827

Consolidation, Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Other (income) expenses:

'

'

'

'

'

'

'

'

'

'

'

(Income) loss from investment in subsidiaries

'

'

'

'

'

'

'

'

214,957

223,480

231,924

Total other (income) expenses

'

'

'

'

'

'

'

'

214,957

223,480

231,924

Income (loss) before taxes

'

'

'

'

'

'

'

'

-214,957

-223,480

-231,924

Provision (benefit) for income taxes:

'

'

'

'

'

'

'

'

'

'

'

Net income (loss)

'

'

'

'

'

'

'

'

-214,957

-223,480

-231,924

Comprehensive income (loss)

'

'

'

'

'

'

'

'

($214,957)

($223,480)

($231,924)

[1]

Includes franchise tax settlement of $12,590 before income tax effect ($8,058, net of income tax effect).

[2]

Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

Condensed_Consolidating_Statem1

Condensed Consolidating Statement of Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income (loss)	$117,634	$149,426	$194,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	350,574	344,365	280,020
Accretion expense	33,575	33,331	30,764
Deferred income tax provision (benefit)	79,629	69,575	129,520
Settlement of asset retirement obligations	-83,854	-65,567	-63,391
Non-cash stock compensation expense	10,347	8,699	5,905
Excess tax benefits	-156	-949	-1,493
Non-cash derivative expense (income)	2,239	-509	-2,216
Loss on early extinguishment of debt	27,279	1,972	607
Non-cash interest expense	16,219	13,085	1,908
Other non-cash income	'	'	-1,602
Change in current income taxes	2,767	10,618	-19,451
(Increase) decrease in accounts receivable	-4,683	-55,871	-19,600
(Increase) decrease in other current assets	1,752	-2,836	-66
Decrease in inventory	583	436	1,619
Increase (decrease) in accounts payable	402	5,101	6,039
Decrease in other current liabilities	42,451	-10,426	29,583
Other	-2,553	9,299	-1,628
Net cash provided by (used in) operating activities	594,205	509,749	570,850
Cash flows from investing activities:	'	'	'
Investment in oil and gas properties	-663,299	-555,855	-764,933
Proceeds from sale of oil and gas properties, net of expenses	48,821	403	87,930
Sale of fixed assets	'	134	'
Investment in fixed and other assets	-6,816	-13,370	-2,247
Change in restricted funds	-1,742	'	'
Net cash used in investing activities	-623,036	-568,688	-679,250
Cash flows from financing activities:	'	'	'
Proceeds from bank borrowings	'	25,000	75,000
Repayment of bank borrowings	'	-70,000	-30,000
Proceeds from issuance of senior convertible notes	'	300,000	'
Deferred financing costs of senior convertible notes	'	-8,855	'
Proceeds from sold warrants	'	40,170	'
Payments for purchased call options	'	-70,830	'
Proceeds from issuance of senior notes	489,250	300,000	'
Deferred financing costs	-9,065	-11,966	-4,017
Redemption of senior subordinated notes	'	-200,681	'
Redemption of senior notes	-396,014	'	'
Excess tax benefits	156	949	1,493
Net payments for share-based compensation	-3,733	-3,773	-2,581
Net cash provided by financing activities	80,594	300,014	39,895
Effect of exchange rate changes on cash	-65	'	'
Net change in cash and cash equivalents	51,698	241,075	-68,505
Cash and cash equivalents, beginning of period	279,526	38,451	106,956
Cash and cash equivalents, end of period	331,224	279,526	38,451
Parent [Member]	'	'	'
Cash flows from operating activities:	'	'	'
Net income (loss)	117,634	149,426	194,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	93,579	63,022	17,860
Accretion expense	372	561	15
Deferred income tax provision (benefit)	-41,284	-56,175	-1,403
Non-cash stock compensation expense	10,347	8,699	5,905
Excess tax benefits	-156	-949	-1,493
Loss on early extinguishment of debt	27,279	1,972	607
Non-cash interest expense	16,219	13,085	1,908
Other non-cash income	'	'	-1,602
Non-cash (income) loss from investment in subsidiaries	-214,983	-223,555	-230,861
Change in current income taxes	2,767	10,618	-19,451
Change in intercompany receivables/payables	186,903	275,819	217,287
(Increase) decrease in accounts receivable	-15,630	-22,750	-11,022
(Increase) decrease in other current assets	1,752	-2,836	-80
Decrease in inventory	583	436	1,605
Increase (decrease) in accounts payable	-1,052	5,348	2,658
Decrease in other current liabilities	40,543	-5,311	23,440
Other	419	10,960	-1,628
Net cash provided by (used in) operating activities	225,292	228,370	198,077
Cash flows from investing activities:	'	'	'
Investment in oil and gas properties	-273,474	-324,542	-309,026
Proceeds from sale of oil and gas properties, net of expenses	6,300	403	5,575
Sale of fixed assets	'	134	'
Investment in fixed and other assets	-6,816	-13,370	-2,247
Investment in subsidiaries	-14,000	'	'
Net cash used in investing activities	-287,990	-337,375	-305,698
Cash flows from financing activities:	'	'	'
Proceeds from bank borrowings	'	25,000	75,000
Repayment of bank borrowings	'	-70,000	-30,000
Proceeds from issuance of senior convertible notes	'	300,000	'
Deferred financing costs of senior convertible notes	'	-8,855	'
Proceeds from sold warrants	'	40,170	'
Payments for purchased call options	'	-70,830	'
Proceeds from issuance of senior notes	489,250	300,000	'
Deferred financing costs	-9,065	-11,966	-4,017
Redemption of senior subordinated notes	'	-200,681	'
Redemption of senior notes	-396,014	'	'
Excess tax benefits	156	949	1,493
Net payments for share-based compensation	-3,733	-3,773	-2,581
Net cash provided by financing activities	80,594	300,014	39,895
Net change in cash and cash equivalents	17,896	191,009	-67,726
Cash and cash equivalents, beginning of period	228,398	37,389	105,115
Cash and cash equivalents, end of period	246,294	228,398	37,389
Guarantor Subsidiary [Member]	'	'	'
Cash flows from operating activities:	'	'	'
Net income (loss)	215,009	223,555	232,751
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	256,995	281,152	261,326
Accretion expense	33,203	32,513	30,385
Deferred income tax provision (benefit)	120,913	125,750	130,923
Settlement of asset retirement obligations	-83,854	-65,567	-63,391
Non-cash derivative expense (income)	2,239	-509	-2,216
Non-cash (income) loss from investment in subsidiaries	'	75	-1,063
Change in intercompany receivables/payables	-186,947	-275,125	-217,724
(Increase) decrease in accounts receivable	10,947	-33,345	-7,688
(Increase) decrease in other current assets	'	'	14
Decrease in inventory	'	'	14
Increase (decrease) in accounts payable	1,454	-208	3,341
Decrease in other current liabilities	1,908	-5,115	6,143
Other	-2,972	-1,661	'
Net cash provided by (used in) operating activities	368,895	281,515	372,815
Cash flows from investing activities:	'	'	'
Investment in oil and gas properties	-378,254	-231,313	-455,903
Proceeds from sale of oil and gas properties, net of expenses	42,521	'	82,355
Net cash used in investing activities	-335,733	-231,313	-373,548
Cash flows from financing activities:	'	'	'
Net change in cash and cash equivalents	33,162	50,202	-733
Cash and cash equivalents, beginning of period	51,128	926	1,659
Cash and cash equivalents, end of period	84,290	51,128	926
Non-Guarantor Subsidiaries [Member]	'	'	'
Cash flows from operating activities:	'	'	'
Net income (loss)	-52	-75	-827
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	'	191	834
Accretion expense	'	257	364
Non-cash (income) loss from investment in subsidiaries	26	'	'
Change in intercompany receivables/payables	44	-694	437
(Increase) decrease in accounts receivable	'	224	-890
Increase (decrease) in accounts payable	'	-39	40
Net cash provided by (used in) operating activities	18	-136	-42
Cash flows from investing activities:	'	'	'
Investment in oil and gas properties	-11,571	'	-4
Change in restricted funds	-1,742	'	'
Investment in subsidiaries	-13,404	'	'
Net cash used in investing activities	-26,717	'	-4
Cash flows from financing activities:	'	'	'
Equity proceeds from parent	27,404	'	'
Net cash provided by financing activities	27,404	'	'
Effect of exchange rate changes on cash	-65	'	'
Net change in cash and cash equivalents	640	-136	-46
Cash and cash equivalents, beginning of period	'	136	182
Cash and cash equivalents, end of period	640	'	136
Consolidation, Eliminations [Member]	'	'	'
Cash flows from operating activities:	'	'	'
Net income (loss)	-214,957	-223,480	-231,924
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	'	'	'
Non-cash (income) loss from investment in subsidiaries	214,957	223,480	231,924
Cash flows from investing activities:	'	'	'
Investment in subsidiaries	27,404	'	'
Net cash used in investing activities	27,404	'	'
Cash flows from financing activities:	'	'	'
Equity proceeds from parent	-27,404	'	'
Net cash provided by financing activities	($27,404)	'	'