Stone Energy (SGY) 10-K 26 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 24, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	SGY
Entity Registrant Name	STONE ENERGY CORP
Entity Central Index Key	904080
Current Fiscal Year End Date	-19
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		55,916,305
Entity Public Float			$2.60

CONSOLIDATED_BALANCE_SHEET

CONSOLIDATED BALANCE SHEET (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$74,488		$331,224		$279,526	$38,451
Restricted cash	177,647
Accounts receivable	120,359		171,971
Fair value of derivative contracts	139,179		4,549
Current income tax receivable	7,212		7,366
Deferred taxes			31,710	[1]
Inventory	3,709		3,723
Other current assets	8,118		1,874
Total current assets	530,712		552,417
Oil and gas properties, full cost method of accounting:
Proved	8,817,268		7,804,117
Less: accumulated depreciation, depletion and amortization	-6,970,631		-5,908,760
Net proved oil and gas properties	1,846,637		1,895,357
Unevaluated	567,365		724,339
Other property and equipment, net of accumulated depreciation of $24,091 and $21,748, respectively	32,340		26,178
Fair value of derivative contracts	14,333		1,378
Other assets, net of accumulated depreciation and amortization of $8,478 and $5,768, respectively	27,224		48,887
Total assets	3,018,611		3,248,556
Current liabilities:
Accounts payable to vendors	132,629		195,677
Undistributed oil and gas proceeds	23,232		37,029
Accrued interest	9,022		9,022
Deferred taxes	20,119	[1]
Fair value of derivative contracts			7,753
Asset retirement obligations	69,400		67,161
Other current liabilities	49,505		54,520
Total current liabilities	303,907		371,162
Long-term debt	1,041,035		1,027,084
Deferred taxes	286,343	[1]	390,693	[1]
Asset retirement obligations	247,009		435,352
Fair value of derivative contracts			470
Other long-term liabilities	38,714		53,509
Total liabilities	1,917,008		2,278,270
Commitments and contingencies
Stockholders' equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 54,884,542 and 48,750,533 shares, respectively	549		488
Treasury stock (16,582 shares, at cost)	-860		-860
Additional paid-in capital	1,633,307		1,397,885
Accumulated deficit	-614,708		-425,165
Accumulated other comprehensive income (loss)	83,315		-2,062		28,833
Total stockholders' equity	1,101,603		970,286
Total liabilities and stockholders' equity	$3,018,611		$3,248,556
[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, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Other property and equipment, accumulated depreciation	$24,091	$21,748
Other assets, accumulated depreciation and amortization	$8,478	$5,768
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	54,884,542	48,750,533
Treasury stock, shares	16,582	16,582

CONSOLIDATED_STATEMENT_OF_OPER

CONSOLIDATED STATEMENT OF OPERATIONS (USD $)	3 Months Ended											12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenue:
Oil production												$516,104	$715,104	$761,304
Natural gas production												166,494	190,580	134,739
Natural gas liquids production												85,642	60,687	48,498
Other operational income												7,951	7,808	3,520
Derivative income, net												19,351		3,428
Total operating revenue	184,780		183,213		207,046	223,830	239,253		256,685	245,877	233,732	795,542	974,179	951,489
Operating expenses:
Lease operating expenses												176,495	201,153	215,003
Transportation, processing and gathering expenses												64,951	42,172	21,782
Production taxes												12,151	15,029	10,015
Depreciation, depletion and amortization												340,006	350,574	344,365
Write-down of oil and gas properties	304,062		47,130									351,192
Accretion expense												28,411	33,575	33,331
Salaries, general and administrative expenses												66,451	59,524	54,648
Franchise tax settlement							12,590						12,590
Incentive compensation expense												10,361	15,340	8,113
Other operational expenses												862	151	267
Derivative expense, net													2,090
Total operating expenses												1,050,880	732,198	687,524
Income (loss) from operations	-286,147	[1]	-34,356	[2]	16,613	48,552	37,206	[3]	62,422	69,525	72,828	-255,338	241,981	263,965
Other (income) expenses:
Interest expense												38,855	32,837	30,375
Interest income												-574	-1,695	-600
Other income												-2,332	-2,799	-1,805
Other expense												274
Loss on early extinguishment of debt							27,279						27,279	1,972
Total other (income) expenses												36,223	55,622	29,942
Income (loss) before income taxes												-291,561	186,359	234,023
Provision (benefit) for income taxes:
Current												159	-10,904	15,022
Deferred												-102,177	79,629	69,575
Total income taxes												-102,018	68,725	84,597
Net income (loss)	($190,515)	[1]	($29,415)	[2]	$4,444	$25,943	$1,752	[3],[4]	$36,102	$39,022	$40,758	($189,543)	$117,634	$149,426
Basic earnings (loss) per share	($3.47)		($0.54)		$0.08	$0.52	$0.04		$0.72	$0.78	$0.82	($3.60)	$2.36	$3.03
Diluted earnings (loss) per share	($3.47)		($0.54)		$0.08	$0.52	$0.04		$0.72	$0.78	$0.82	($3.60)	$2.36	$3.03
Average shares outstanding												52,721	48,693	48,319
Average shares outstanding assuming dilution												52,721	48,735	48,361
[1]	Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).
[2]	Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).
[3]	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
[4]	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

CONSOLIDATED_STATEMENT_OF_COMP

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Statement of Comprehensive Income [Abstract]

Net income (loss)

($190,515)

[1]

($29,415)

[2]

$4,444

$25,943

$1,752

[3],[4]

$36,102

$39,022

$40,758

($189,543)

$117,634

$149,426

Other comprehensive income (loss), net of tax effect:

Derivatives

88,178

-30,228

6,965

Foreign currency translation

-2,801

-667

Comprehensive income (loss)

($104,166)

$86,739

$156,391

[1]

Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).

[2]

Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).

[3]

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

[4]

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	($189,543)	$117,634	$149,426
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	340,006	350,574	344,365
Write-down of oil and gas properties	351,192
Accretion expense	28,411	33,575	33,331
Deferred income tax (benefit) provision	-102,177	79,629	69,575
Settlement of asset retirement obligations	-56,409	-83,854	-65,567
Non-cash stock compensation expense	11,325	10,347	8,699
Excess tax benefits		-156	-949
Non-cash derivative (income) expense	-18,028	2,239	-509
Loss on early extinguishment of debt		27,279	1,972
Non-cash interest expense	16,661	16,219	13,085
Change in current income taxes	158	2,767	10,618
(Increase) decrease in accounts receivable	51,611	-4,683	-55,871
(Increase) decrease in other current assets	-6,244	1,752	-2,836
Decrease in inventory		583	436
Increase (decrease) in accounts payable	-3,419	402	5,101
Increase (decrease) in other current liabilities	-19,152	42,451	-10,426
Other	-3,251	-2,553	9,299
Net cash provided by operating activities	401,141	594,205	509,749
Cash flows from investing activities:
Investment in oil and gas properties	-927,247	-663,299	-555,855
Proceeds from sale of oil and gas properties, net of expenses	242,914	48,821	403
Sale of fixed assets			134
Investment in fixed and other assets	-10,182	-6,816	-13,370
Change in restricted funds	-178,072	-1,742
Net cash used in investing activities	-872,587	-623,036	-568,688
Cash flows from financing activities:
Proceeds from bank borrowings			25,000
Repayments of bank borrowings			-70,000
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
Net proceeds from issuance of common stock	225,999
Deferred financing costs	-3,371	-9,065	-11,966
Redemption of senior notes		-396,014
Redemption of senior subordinated notes			-200,681
Excess tax benefits		156	949
Net payments for share-based compensation	-7,182	-3,733	-3,773
Net cash provided by financing activities	215,446	80,594	300,014
Effect of exchange rate changes on cash	-736	-65
Net change in cash and cash equivalents	-256,736	51,698	241,075
Cash and cash equivalents, beginning of year	331,224	279,526	38,451
Cash and cash equivalents, end of year	74,488	331,224	279,526
Supplemental cash flow information:
Cash paid for interest, net of amount capitalized	-14,076	-29,883	-20,150
Cash (paid) refunded for income taxes	($1)	$13,670	($4,405)

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, 2011	$667,829	$481	($860)	$1,338,565	($692,225)	$21,868
Net income (loss)	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 (loss)	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
Net income (loss)	-189,543				-189,543
Adjustment for fair value accounting of derivatives, net of tax	88,178					88,178
Adjustment for foreign currency translation, net of tax	-2,801					-2,801
Exercise of stock options and vesting of restricted stock	-7,171	3		-7,174
Amortization of stock compensation expense	16,709			16,709
Net tax impact from stock option exercises and restricted stock vesting	-54			-54
Issuance of common stock	225,999	58		225,941
Ending Balance at Dec. 31, 2014	$1,101,603	$549	($860)	$1,633,307	($614,708)	$83,315

ORGANIZATION_AND_SUMMARY_OF_SI

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2014
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 began operating in the Gulf of Mexico (the “GOM”) Basin in 1993 and have established a technical and operational expertise in that area. We have leveraged our experience in the GOM conventional shelf and expanded our reserve base into the more prolific basins of the GOM deep water, Gulf Coast deep gas and the Marcellus Shale in Appalachia. During 2014, we sold our non-core GOM conventional shelf properties to allow for more focus on these targeted growth areas. 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. and Stone Energy Canada, U.L.C. 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, income 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 contracts, 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, 2014 and 2013, 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.
	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 shareholders 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 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.
	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, the computation of DD&A expense and the assessment of impairment of oil and gas properties. 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. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.
	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 period reserves being determined by adding production to the end of 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 (adjusted for hedges and 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 net oil and gas properties 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 lives 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 considered 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 or underdelivered 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 and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2012, 2013 and 2014, 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 as a hedging instrument. Instruments that qualify as a hedging instrument, with contemporaneous documentation, are recorded as either an asset or liability, measured at fair value, with subsequent changes in the derivative’s fair value recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments 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 and derivative instruments not qualifying as hedging instruments are recognize in earnings through derivative expense (income) and cash flows from operating activities.
	Share-Based Compensation:
	We record share-based compensation using 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, 2014
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,
		2014		2013		2012
	Income (numerator):
	Basic:
	Net income (loss)		($189,543)		$117,634		$149,426
	Net income attributable to participating securities		-		(2,817)		(2,984)
	Net income (loss) attributable to common stock - basic		($189,543)		$114,817		$146,422
	Diluted:
	Net income (loss)		($189,543)		$117,634		$149,426
	Net income attributable to participating securities		-		(2,815)		(2,982)
	Net income (loss) attributable to common stock - diluted		($189,543)		$114,819		$146,444
	Weighted average shares (denominator):
	Weighted average shares - basic		52,721		48,693		48,319
	Dilutive effect of stock options		-		42		42
	Weighted average shares - diluted		52,721		48,735		48,361
	Basic earnings (loss) per share		($3.60)		$2.36		$3.03
	Diluted earnings (loss) per share		($3.60)		$2.36		$3.03
	All outstanding stock options were considered antidilutive during the year ended December 31, 2014 (205,000 shares) because we had a net loss for such period. 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 and 347,000 shares during the years ended December 31, 2013 and 2012, respectively.
	During the years ended December 31, 2014, 2013 and 2012, approximately 384,000, 358,000 and 316,000 shares of our common stock, respectively, were issued from authorized shares upon the lapsing of forfeiture restrictions of restricted stock and the exercise of stock options by employees and nonemployee directors. In May 2014, 5,750,000 shares of our common stock were issued in a public offering (see Note 3 – Common Stock Offering).
	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 dilution in the diluted earnings per share computation. For the year ended December 31, 2014, there was no dilutive effect on the diluted earnings per share computation as we had a net loss for such year. For the years ended December 31, 2013 and 2012, the average price of our common stock was less than the effective conversion price for such notes, resulting in no dilutive effect on the diluted earnings per share computation for such years. For the years ended December 31, 2014, 2013 and 2012, 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) and therefore, such warrants were not dilutive for such years. Based on the terms of the Purchased Call Options (as defined in Note 11 – Long-Term Debt), such call options are antidilutive and therefore, were not included in the calculation of diluted earnings per share.

COMMON_STOCK_OFFERING

COMMON STOCK OFFERING	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
COMMON STOCK OFFERING	NOTE 3 — COMMON STOCK OFFERING:
	In May 2014, we sold 5,750,000 shares of our common stock in a public offering at a price of $41.00 per share resulting in net proceeds of approximately $225,999 after deducting the underwriting discount and offering expenses.

ACCOUNTS_RECEIVABLE

ACCOUNTS RECEIVABLE	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
ACCOUNTS RECEIVABLE	NOTE 4 — 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,
		2014		2013
	Other co-venturers		$16,291		$13,904
	Trade		60,263		134,622
	Unbilled accounts receivable		33,052		22,001
	Other		10,753		1,444
	Total accounts receivable		$120,359		$171,971

CONCENTRATIONS

CONCENTRATIONS	12 Months Ended
	Dec. 31, 2014
Risks and Uncertainties [Abstract]
CONCENTRATIONS	NOTE 5 — 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 indicated periods:
		Year Ended December 31,
		2014			2013			2012
	Conoco, Inc.		(a	)		(a	)		13	%
	Phillips 66 Company		31	%		35	%		18	%
	Shell Trading (US) Company		32	%		33	%		41	%
	(a)    Less than 10 percent.
	The maximum amount of credit risk exposure at December 31, 2014 relating to these customers was $31,929.
	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 42% of our estimated proved reserves at December 31, 2014 and 60% of our production during 2014 were associated with our GOM deep water, conventional shelf and deep gas properties. Approximately 58% of our estimated proved reserves at December 31, 2014 and 40% of our production during 2014 were associated with our Appalachian properties.
	Cash and Cash Equivalents
	A substantial portion of our cash balances are not federally insured.

DIVESTITURES

DIVESTITURES	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
DIVESTITURES	NOTE 6 — DIVESTITURES:
	On January 16, 2014, we completed the sales of our interests in the Cut Off and Clovelly fields (onshore Louisiana) for cash consideration at closing of approximately $44,804 and the assumption of the associated asset retirement obligations of approximately $9,162. On July 31, 2014, we completed the sale of certain non-core properties in the GOM conventional shelf for cash consideration at closing of approximately $177,647, after giving effect to preliminary purchase price adjustments and the assumption of the associated asset retirement obligations of approximately $125,198. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 9% of our total estimated proved oil and natural gas reserves. Additionally, in 2014, we completed the sales of our interests in other non-core fields, including Katie (Pennsylvania), Hatch Point (Utah), Falls City (Texas) and South Marsh Island Block 192 (GOM), for a combined cash consideration of approximately $26,065 and the assumption of the associated asset retirement obligations of approximately $3,440. At December 31, 2013, the estimated proved reserves associated with these assets represented approximately 2% of our total estimated proved oil and natural gas reserves. These sales were accounted for as reductions to net proved oil and gas properties, with total cash consideration and the assumed asset retirement obligation recorded as an increase to accumulated DD&A. No gain or loss was recognized since the adjustments did not significantly alter the relationship between capitalized costs and proved reserves.
	All of the proceeds from the July 31, 2014 sale of certain of our non-core GOM conventional shelf properties were deposited with a Qualified Intermediary (under the terms of a Qualified Trust Agreement and Exchange Agreement) for potential reinvestment in like-kind replacement property as defined under Section 1031 of the Internal Revenue Code, and are included in our balance sheet as restricted cash at December 31, 2014. Compliance with provisions under the Qualified Trust Agreement and Exchange Agreement provides for deferral of taxable gain on these sales proceeds. We identified qualified replacement properties and had until January 27, 2015 to close on such properties in order to achieve deferral of our taxable gain. We did not close on such a transaction by January 27, 2015 and the funds were released from restrictions and reclassified to cash and cash equivalents at such date.
	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 a reduction of net proved oil and gas properties with no gain or loss recognized.

DERIVATIVE_INSTRUMENTS_AND_HED

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2014
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 derivative transactions to secure a commodity price for a portion of our expected future production that is acceptable at the time of the transaction. These derivatives are generally designated as cash flow hedges upon entering into the contracts. We do not enter into derivative transactions for trading purposes. We have no fair value hedges.
	The nature of a derivative instrument must be evaluated to determine if it qualifies as a hedging instrument. If the instrument qualifies as a hedging instrument, 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. Monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments 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 and derivative instruments not qualifying as hedging instruments are recognized in earnings through derivative expense (income) and cash flows from operating activities.
	We have entered into fixed-price swaps with various counterparties for a portion of our expected 2015 and 2016 oil and natural gas production from the Gulf Coast Basin. 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. 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, The Bank of Nova Scotia, Bank of America and Natixis.
	The following table illustrates our derivative positions for calendar years 2015 and 2016 as of February 24, 2015:
			Fixed-Price Swaps (NYMEX)
			Natural Gas								Oil
			Daily Volume				Swap Price				Daily Volume			Swap Price
			(MMBtus/d)				($/MMBtu)							($/Bbl)
											(Bbls/d)
	2015			10,000				4.005				1,000			89
	2015			10,000				4.12				1,000			90
	2015			10,000				4.15				1,000			90.25
	2015			10,000				4.165				1,000			90.4
	2015			10,000				4.22				1,000			91.05
	2015			10,000				4.255				1,000			93.28
	2015											1,000			93.37
	2015											1,000			94.85
	2015											1,000			95
	2016			10,000				4.11				1,000			90
	2016			10,000				4.12
	All of our derivative instruments at December 31, 2013 and 2012 were designated as effective cash flow hedges. During 2014, certain of our natural gas derivative instruments no longer qualified as cash flow hedges, as it was no longer probable, subsequent to the sale of our non-core GOM conventional shelf properties (see Note 6 – Divestitures), that GOM natural gas production would be sufficient to cover the GOM volumes hedged. Accordingly, we discontinued hedge accounting for such contracts. Natural gas contracts no longer qualifying as cash flow hedges included three contracts for the month of August 2014, four contracts for the months of September through December 2014 and three contracts for the months of January through December 2015. Additionally, a small portion of our cash flow hedges are typically determined to be ineffective 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. At December 31, 2014, we had accumulated other comprehensive income of $86,783, net of tax, related to the fair value of our effective cash flow hedges that were outstanding as of December 31, 2014. We believe that approximately $77,991, net of tax, of accumulated other comprehensive income will be reclassified into earnings in the next 12 months.
	Derivatives qualifying as hedging instruments:
	The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2014 and 2013:
	Fair Value of Derivatives Qualifying as Hedging Instruments at December 31, 2014
			Asset Derivatives						Liability Derivatives
	Description		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of derivative contracts			$127,033			Current liabilities: Fair value of derivative contracts			$  -
			Long-term assets: Fair value of derivative contracts			14,333			Long-term liabilities: Fair value of derivative contracts			-
						$141,366						$  -
	Fair Value of Derivatives Qualifying as Hedging 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 derivative contracts			$4,549			Current liabilities: Fair value of derivative contracts			$7,753
			Long-term assets: Fair value of derivative contracts			1,378			Long-term liabilities: Fair value of derivative contracts			470
						$5,927						$8,223
	The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2014, 2013 and 2012:
	Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
	for the Years Ended December 31, 2014, 2013 and 2012
	Derivatives in Cash		Amount of Gain				Gain (Loss) Reclassified from						Gain (Loss) Recognized in Income
			(Loss) Recognized
	Flow Hedging		in Other				Accumulated Other Comprehensive Income						on Derivatives
			Comprehensive				into Income
	Relationships		Income on										(Ineffective Portion)
			Derivatives				(Effective Portion) (a)
							Location						Location
			2014						2014					2014
	Commodity contracts			$136,097			Operating revenue -			$526			Derivative income, net		$5,721
							oil/gas production
	Total			$136,097						$526					$5,721
			2013						2013					2013
	Commodity contracts			($26,945)			Operating revenue -			$20,289			Derivative expense, net		($2,090)
							oil/gas production
	Total			($26,945)						$20,289					($2,090)
			2012						2012					2012
	Commodity contracts			$41,209			Operating revenue -			$30,326			Derivative income, net		$3,428
							oil/gas production
	Total			$41,209						$30,326					$3,428
		(a)	For the year ended December 31, 2014, effective hedging contracts increased oil revenue by $7,929 and decreased gas revenue by $7,403. 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.
	Derivatives not qualifying as hedging instruments:
	The following table discloses the location and fair value amounts of our derivatives not qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2014. All of our derivatives at December 31, 2013 qualified as hedging instruments.
	Fair Value of Derivatives Not Qualifying as Hedging Instruments at December 31, 2014
	Description		Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of derivative contracts		$	12,146
Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the year ended December 31, 2014:
Amount of Gain Recognized in Derivative Income
Description		Year Ended
		December 31, 2014
Commodity contracts:
Cash settlements			$1,484
Change in fair value			12,146
Total gains on non-qualifying hedges			$13,630
Offsetting of derivative assets and liabilities:
Our derivative contracts are subject to netting arrangements. It is our policy to not offset our derivative contracts in presenting the fair value of these contracts as assets and liabilities in our balance sheet. As of December 31, 2014, all of our derivative contracts were in an asset position and therefore, there was no potential impact of the rights of offset. 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 derivative contracts			$4,549				($4,043)				$506
Long-term assets: Fair value of derivative contracts			1,378				(274)				1,104
Current liabilities: Fair value of derivative contracts			(7,753)				4,043				(3,710)
Long-term liabilities: Fair value of derivative contracts			(470)				274				(196)

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013, 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, 2014:
		Fair Value Measurements at December 31, 2014
	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 (Other assets)		$8,425		$8,425		$  -		$  -
	Derivative contracts		153,512		-		153,512		-
	Total		$161,937		$8,425		$153,512		$  -
		Fair Value Measurements at December 31, 2014
	Liabilities	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Liabilities		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Derivative contracts		$  -		$  -		$  -		$  -
	Total		$  -		$  -		$  -		$  -
	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 (Other assets)		$8,248		$8,248		$  -		$  -
	Derivative 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)
	Derivative contracts		$8,223		$  -		$8,223		$  -
	Total		$8,223		$  -		$8,223		$  -
	The fair value of cash and cash equivalents approximated book value at December 31, 2014 and 2013. As of December 31, 2014 and 2013, the fair value of the liability component of the 2017 Convertible Notes was approximately $252,587 and $260,377, respectively. As of December 31, 2014 and 2013, the fair value of the 7 1⁄2% Senior Notes due 2022 (the “2022 Notes”) was approximately $664,563 and $814,719, respectively.
	The fair value of the 2022 Notes was determined based on quotes obtained from brokers, which represent Level 1 inputs. We applied fair value concepts in determining the liability component of the 2017 Convertible Notes (seeNote 11 – Long-Term Debt) at inception and at December 31, 2014 and 2013. 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, 2014
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, 2014, 2013 and 2012 is set forth below:
		Year Ended December 31,
		2014		2013		2012
	Asset retirement obligations as of the beginning of the year, including current portion		$502,513		$488,302		$425,779
	Liabilities incurred		28,606		19,043		3,869
	Liabilities settled		(55,839)		(79,695)		(67,641)
	Liabilities assumed		-		-		15,263
	Divestment of properties		(137,801)		(9,245)		(7,563)
	Accretion expense		28,411		33,575		33,331
	Revision of estimates		(49,481)		50,533		85,264
	Asset retirement obligations as of the end of the year, including current portion		$316,409		$502,513		$488,302

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
INCOME TAXES	NOTE 10 — INCOME TAXES:
	An analysis of our deferred taxes follows:
		As of December 31,
		2014			2013
	Tax effect of temporary differences:
	Net operating loss carryforwards		$99,615			$24,437
	Oil and gas properties – full cost		(476,367)			(576,393)
	Asset retirement obligations		113,907			180,905
	Stock compensation		5,603			5,537
	Hedges		(54,439)			826
	Accrued incentive compensation		6,185			9,189
	Other		(966)			(3,484)
			($306,462)			($358,983)
	We estimate that we have approximately $159, ($10,904) and $15,022 of current federal income tax expense (benefit) for the years ended December 31, 2014, 2013 and 2012, respectively. We have a $7,212 current income tax receivable at December 31, 2014.
	For tax reporting purposes, net operating loss carryforwards totaled approximately $281,240 at December 31, 2014. If not utilized, such carryforwards would begin expiring in 2033 and would completely expire by the year 2034. In addition, we had approximately $920 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,
		2014		2013	2012
	Income tax expense computed at the statutory federal income tax rate	35.0%		35.0%	35.0%
	State taxes	1.0		1.0	1.0
	IRC Sec. 162(m) limitation	(0.5)		0.8	0.6
	Tax deficits on stock compensation	(0.2)		-	-
	Other	(0.3)		0.1	(0.5)
	Effective income tax rate	35.0%		36.9%	36.1%
	Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to $49,601, ($17,003) and $3,918 for the years ended December 31, 2014, 2013 and 2012, respectively.
	As of December 31, 2014 and 2013, we had no unrecognized tax benefits.
	The tax years 2011 through 2013 remain subject to examination by major tax jurisdictions.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
LONG-TERM DEBT	NOTE 11 — LONG-TERM DEBT:
	Long-term debt consisted of the following at:
			December 31,
			2014		2013
	1 3⁄4% Senior Convertible Notes due 2017			$266,035		$252,084
	7 1⁄2% Senior Notes due 2022			775,000		775,000
	Bank debt			-		-
	Total long-term debt			$1,041,035		$1,027,084
	Bank Debt
	On June 24, 2014, we entered into an amended and restated revolving credit facility with commitments totaling $900,000 (subject to borrowing base limitations) through a syndicated bank group, replacing our previous facility. The bank credit facility matures on July 1, 2019. Our initial borrowing base under the bank credit facility was set at $500,000 and was reaffirmed at $500,000 in October 2014. As of December 31, 2014 and February 24, 2015, we had no outstanding borrowings under the bank credit facility and $19,221 in letters of credit had been issued pursuant to the bank credit facility, leaving $480,779 of availability under the bank credit facility. Subject to certain exceptions, the bank credit facility is required to be guaranteed by all of our material domestic direct and indirect subsidiaries. The bank credit facility is guaranteed by our only material subsidiary, Stone Offshore.
	The borrowing base under the bank credit facility is redetermined semi-annually, usually in May and November, by the lenders, taking into consideration the estimated loan value of our oil and gas properties and those of our subsidiaries that guarantee the bank credit facility 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 six equal monthly installments.
	The 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 proved oil and natural gas reserves reviewed in determining the borrowing base. Interest on loans under the bank credit facility is calculated using the London Interbank Offering (“Libor”) rate or the base rate, at the election of Stone. The margin for loans at the LIBOR rate is determined based on borrowing base utilization and ranges from 1.500% to 2.500%.
	Under the financial covenants of the bank credit facility, we must (1) maintain a ratio of Consolidated Funded Debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.75 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 2.5 to 1. As of December 31, 2014, our Consolidated Funded Debt to consolidated EBITDA ratio was 2.26 to 1 and our consolidated EBITDA to consolidated Net Interest Expense ratio was approximately 12.03 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 control 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, 2014.
	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, 2014, our closing share price was $16.88. 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(a)(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, 2014, the carrying amount of the liability component of the 2017 Convertible Notes was $266,035 and $1,750 had been accrued in connection with the March 1, 2015 interest payment. During the year ended December 31, 2014, we recognized $13,951 of interest expense for the amortization of the discount and $1,332 of interest expense for the amortization of deferred financing costs related to the 2017 Convertible Notes. 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 each of the years ended December 31, 2014 and 2013, we recognized $5,250 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, 2014, $7,266 had been accrued in connection with the May 15, 2015 interest payment.
	Deferred Financing Cost and Interest Cost
	Other assets at December 31, 2014 and 2013 included approximately $12,415 and $11,754, 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 the 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 the bank credit facility are being amortized over the term of the bank credit facility.
	Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2014, 2013 and 2012 was $84,577, $79,697 and $68,031 respectively.

ACCUMULATED_OTHER_COMPREHENSIV

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014 and 2013 were as follows:
		Cash Flow		Foreign		Total
		Hedges		Currency
				Items
	For the Year Ended December 31, 2014
	Beginning balance, net of tax		($1,395)		($667)		($2,062)
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		136,097		-		136,097
	Foreign currency translations		-		(2,801)		(2,801)
	Income tax effect		(48,995)		-		(48,995)
	Net of tax		87,102		(2,801)		84,301
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		526		-		526
	Derivative expense, net		(2,208)		-		(2,208)
	Income tax effect		606		-		606
	Net of tax		(1,076)		-		(1,076)
	Other comprehensive income (loss), net of tax		88,178		(2,801)		85,377
	Ending balance, net of tax		$86,783		($3,468)		$83,315
		Cash Flow		Foreign		Total
		Hedges		Currency
				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 loss, net of tax		(30,228)		(667)		(30,895)
	Ending balance, net of tax		($1,395)		($667)		($2,062)
	In 2012, the only component of accumulated other comprehensive income related to our cash flow hedges. Changes in accumulated other comprehensive income for the year ended December 31, 2012 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

SHAREBASED_COMPENSATION

SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
SHARE-BASED COMPENSATION	NOTE 13 — SHARE-BASED COMPENSATION:
	Under the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan, as amended from time to time (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 vested ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to non-employee directors vested 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 share-based compensation awards based on the fair value on the date of grant. Compensation expense for share-based compensation awards is recognized in our financial statements over the vesting period of the award.
	For the year ended December 31, 2014, we incurred $17,051 of share-based compensation, all of which related to restricted stock issuances, and of which a total of approximately $5,797 was capitalized into oil and gas properties. 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. 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, 2014, 2013 or 2012.
	A summary of stock option activity under the 2009 Plan during the year ended December 31, 2014 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		331,174		$39.37
	Granted		-		-
	Exercised		(250)		46.20
	Forfeited		-		-
	Expired		(125,950)		48.21
	Options outstanding, end of period		204,974		33.94		2.4 years		$531
	Options exercisable, end of period		204,974		33.94		2.4 years		531
	Options unvested, end of period		-		-		-		-
	Exercise prices for stock options outstanding at December 31, 2014 range from $6.97 to $53.20.
	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
	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		41.00		2.5 years		459
	Options unvested, end of period		33,790		17.17		5.4 years		307
	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, 2014, we issued 674,904 shares of restricted stock valued at $24,593. 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.
	A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2014, 2013 and 2012 is as follows (amounts in table represent actual values):
		2014				2013				2012
		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		1,258,053		$23.92		1,108,874		$27.56		923,740		$20.08
	Issuances		674,904		36.44		848,498		20.61		670,818		31.43
	Lapse of restrictions		(598,796)		24.57		(534,041)		25.45		(462,141)		18.29
	Forfeitures		(31,055)		30.19		(165,278)		26.43		(23,543)		26.10
	Restricted stock outstanding, end of period		1,303,106		$29.95		1,258,053		$23.92		1,108,874		$27.56
	As of December 31, 2014, there was $22,354 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 1.8 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 and/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 ($54), ($884) and $814 in 2014, 2013 and 2012, respectively. Additionally, during 2014, $609 of tax deficits were charged to income tax expense.

SHARE_REPURCHASE_PROGRAM

SHARE REPURCHASE PROGRAM	12 Months Ended
	Dec. 31, 2014
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, 2014, 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, 2014, 2013 and 2012.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
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 New Martinsville and Morgantown, West Virginia under the terms of long-term, non-cancelable leases expiring on various dates through 2025. 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, 2014 were as follows:
	2015	$1,416
	2016	1,571
	2017	1,524
	2018	1,339
	2019	1,194
	2020	1,206
	2021	879
	2022	779
	2023	792
	2024	805
	2025	474
	Payments related to our lease obligations for the years ended December 31, 2014, 2013 and 2012 were approximately $966, $597 and $894, respectively.
	Other Commitments
	We are contingently liable to surety insurance companies in the amount of $78,070 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 $352,660 to be incurred over the next four years.
	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 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 party in certain lawsuits and 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.
	In August 2013, Kimmeridge Energy Exploration Fund, L.P. (“Kimmeridge”) filed a lawsuit against Stone in the 15th Judicial District Court in Lafayette Parish, Louisiana seeking damages in the amount of approximately $18,373 plus interest, costs and attorney fees. Kimmeridge alleges that (1) Stone failed to pay brokerage costs of $1,119 incurred after December 31, 2012 pursuant to a letter of understanding, and (2) Stone owes $17,254 to Kimmeridge by virtue of a letter of intent obligating Stone to negotiate in good faith and close an acquisition involving approximately 33,000 net mineral acres in the Illinois basin. The court granted summary judgment in favor of Stone limiting damages at trial on Kimmeridge’s second claim to $1,000. Accordingly, at this time, total exposure to Stone at trial is $2,119. Stone continues to vigorously defend against both claims. We estimate the potential range of loss upon resolution of this matter to be between $0 and $2,119.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2014
Compensation Related Costs [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, 2014, the liability for such vested benefits was approximately $858 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 $10,361, $15,340, and $8,113, net of amounts capitalized, for each of the years ended December 31, 2014, 2013 and 2012, 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 increased 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 was originally approved at the 2009 Annual Meeting of Stockholders and 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, options that are not qualified as incentive stock options and restricted stock awards or any combination as is best suited to the circumstances of the particular employee or nonemployee director, except that only employees may receive incentive stock options. 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 or a designated committee. All options granted under the 2009 Plan 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 vested ratably over a five-year service-vesting period and expire 10 years subsequent to award. Stock options issued to non-employee directors vested ratably over a three-year service-vesting period and expire 10 years subsequent to award. 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, 2014, we had approximately 1,563,967 additional shares available for issuance pursuant to the 2009 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, 2014, 2013 and 2012, Stone contributed $1,989, $1,793 and $1,759, 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 eligible 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, 2014 and 2013, plan assets of $8,425 and $8,248, 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. Although our CEO does not currently participate in the Executive Plan, the severance benefits provided to him under his employee agreement are substantially similar to the benefits provided under 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: (i) any unpaid base salary up to the date of termination; (ii) in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of the executive’s annual base salary and any target bonus at the one hundred percent level; (iii) 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; (iv) 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; (v) 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; (vi) 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,” the CEO and CFO may receive a potential gross-up payment to reimburse them for excise taxes that might be incurred under Section 4999 of the Internal Revenue Code of 1986, as amended (the “Code”), as well as any additional income taxes resulting from such reimbursement, provided that if it shall be determined that the executive is entitled to a gross-up payment but the total to be paid does not exceed 110% of the greatest amount (the “Reduced Amount”) that could be paid such that receipt of the total would not give rise to any excise tax, then no gross-up will be paid and the total payments to the executive will be reduced to the Reduced Amount. 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: (i) lapse of restrictions on restricted stock, (ii) accelerated vesting and cash-out of all in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) 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 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: (i) 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; (ii) continued health plan coverage for six months; and (iii) 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: (i) lapse of restrictions on restricted stock, (ii) accelerated vesting and cash-out of all in-the-money stock options, (iii) a 401(k) plan employer matching contribution at the rate of 50%, and (iv) a lump sum cash payment equal to the product of (1) 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 (2) 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.

SUPPLEMENTAL_INFORMATION_ON_OI

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED	NOTE 17 — SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS – UNAUDITED:
	At December 31, 2014 and 2013, our oil and gas properties were located in the United States and Canada. At December 31, 2012, all of our oil and gas properties were located in the United States.
	Costs Incurred
	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,
		2014		2013		2012
	Oil and gas properties – United States, proved and unevaluated:
	Balance, beginning of year		$8,517,873		$7,692,261		$7,049,777
	Costs incurred during the year (capitalized):
	Acquisition costs, net of sales of unevaluated properties		44,634		70,903		102,807
	Exploratory costs		270,850		297,113		81,458
	Development costs (1)		438,334		378,242		395,555
	Salaries, general and administrative costs		33,975		32,815		25,318
	Interest		45,722		46,860		37,656
	Less: overhead reimbursements		(3,334)		(321)		(310)
	Total costs incurred during the year, net of divestitures		830,181		825,612		642,484
	Balance, end of year		$9,348,054		$8,517,873		$7,692,261
	Accumulated DD&A:
	Balance, beginning of year		($5,908,760)		($5,510,166)		($5,174,729)
	Provision for DD&A		(335,987)		(346,827)		(341,096)
	Write-down of oil and gas properties		(351,192)		-		-
	Sale of proved properties		(374,692)		(51,767)		5,659
	Balance, end of year		($6,970,631)		($5,908,760)		($5,510,166)
	Net capitalized costs – United States, proved and unevaluated		$2,377,423		$2,609,113		$2,182,095
	DD&A per Mcfe		$3.59		$3.43		$3.69
	(1) Includes capitalized asset retirement costs of ($20,305), $54,737 and $95,293, respectively.
	Costs incurred during the year (expensed):
	Lease operating expenses		$176,495		$201,153		$215,003
	Transportation, processing and gathering expenses		64,951		42,172		21,782
	Production taxes		12,151		15,029		10,015
	Accretion expense		28,411		33,575		33,331
	Expensed costs – United States		$282,008		$291,929		$280,131
	Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (adjusted for hedges and 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. At September 30, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $47,130 based on twelve month average prices, net of applicable differentials, of $94.94 per barrel of oil, $4.19 per Mcf of natural gas and $41.33 per barrel of natural gas liquids. At December 31, 2014, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $304,062 based on twelve month average prices, net of applicable differentials, of $89.46 per barrel of oil, $3.68 per Mcf of natural gas and $36.79 per barrel of natural gas liquids. The September 30 and December 31, 2014 write-downs were increased by $29,001 and $13,342, respectively, as a result of hedges.
	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,
	Unevaluated oil and gas properties – United States:	2014		2013		2012
	Net costs incurred (evaluated) during year:
	Acquisition costs		($42,384)		$30,271		$9,739
	Exploration costs		(186,308)		188,830		(1,209)
	Capitalized interest		45,722		46,860		37,656
			($182,970)		$265,961		$46,186
	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 activities located in Canada:
		Year Ended December 31,
		2014		2013
	Oil and gas properties – Canada, unevaluated:
	Balance, beginning of year		$10,583		$  -
	Costs incurred during the year (capitalized):
	Acquisition costs		6,956		8,764
	Exploratory costs		19,040		1,819
	Total costs incurred during the year		25,996		10,583
	Balance, end of year, unevaluated		$36,579		$10,583
	The following table discloses financial data associated with unevaluated costs (United States and Canada) at December 31, 2014:
		Balance as of		Net Costs Incurred During the
		December 31,		Year Ended December 31,
		2014		2014		2013		2012		2011
										and prior
	Acquisition costs		$285,896		$7,330		$82,990		$24,736		$170,840
	Exploration costs		167,510		66,512		78,684		5,318		16,996
	Capitalized interest		113,959		22,352		36,137		21,993		33,477
	Total unevaluated costs		$567,365		$96,194		$197,811		$52,047		$221,313
	Approximately 108 specifically identified drilling projects are included in unevaluated costs at December 31, 2014 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, 2014, 2013 and 2012 totaled $45,722, $46,860 and $37,656, respectively.
	Proved Oil and Natural Gas Quantities
	Our estimated net proved oil and natural gas reserves at December 31, 2014 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 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, 2014, 2013 and 2012 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption.
	Oil		NGLs		Natural		Oil,
	(MBbls)		(MBbls)		Gas		Natural
					(MMcf)		Gas and
							NGLs
							(MMcfe)
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
Revisions of previous estimates		(624)		(331)		(4,631)		(10,362)
Extensions, discoveries and other additions		9,650		7,521		131,617		234,639
Sale of reserves		(4,888)		(556)		(46,483)		(79,151)
Production		(5,568)		(2,114)		(47,426)		(93,515)
Estimated proved reserves as of December 31, 2014		42,397		27,817		493,843		915,124
Estimated proved developed reserves:
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
as of December 31, 2014		22,957		13,743		249,924		470,118
Estimated proved undeveloped reserves:
as of December 31, 2012		15,913		9,473		184,418		336,745
as of December 31, 2013		15,907		11,728		213,820		379,628
as of December 31, 2014		19,440		14,074		243,919		445,006
The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.
Year Ended December 31, 2014.  Extensions, discoveries and other additions were primarily the result of our Appalachia (118 Bcfe) and our deep water (116 Bcfe) drilling programs. Sale of reserves primarily relates to the sale of certain of our non-core GOM conventional shelf properties (63 Bcfe) and our Katie field in Appalachia (15 Bcfe).
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 (18 Bcfe) and well performance (55 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.
Standardized Measure of Discounted Future Net Cash Flow
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, 2014. 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 2014 average historical 12-month oil and gas prices, net of applicable differentials, were $89.46 per Bbl of oil, $36.79 per Bbl of NGLs and $3.68 per Mcf of gas. The 2013 average 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. 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,
	2014		2013		2012
Future cash inflows		$  6,635,751		$  7,040,928		$  6,295,455
Future production costs		(2,413,004)		(2,062,657)		(1,946,426)
Future development costs		(1,511,687)		(1,431,101)		(1,241,531)
Future income taxes		(609,516)		(884,637)		(799,007)
Future net cash flows		2,101,544		2,662,533		2,308,491
10% annual discount		(682,752)		(977,531)		(794,632)
Standardized measure of discounted future net cash flows		$  1,418,792		$  1,685,002		$  1,513,859
	Changes in Standardized Measure
	Year Ended December 31,
	2014		2013		2012
Standardized measure at beginning of year		$1,685,002		$1,513,859		$1,542,962
Sales and transfers of oil, gas and NGLs produced, net of production costs		(486,232)		(708,017)		(697,741)
Changes in price, net of future production costs		(864,118)		229,425		(380,841)
Extensions and discoveries, net of future production and development costs		549,649		155,592		178,272
Changes in estimated future development costs, net of development costs incurred during the period		203,026		28,684		212,329
Revisions of quantity estimates		(27,495)		281,558		76,450
Accretion of discount		222,009		202,087		207,292
Net change in income taxes		209,323		(28,084)		22,947
Purchases of reserves in-place		-		-		276,389
Sales of reserves in-place		(152,787)		15,531		2,480
Changes in production rates due to timing and other		80,415		(5,633)		73,320
Net increase (decrease) in standardized measure		(266,210)		171,143		(29,103)
Standardized measure at end of year		$1,418,792		$1,685,002		$1,513,859

SUMMARIZED_QUARTERLY_FINANCIAL

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED	12 Months Ended
	Dec. 31, 2014
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:
			2014 Quarter Ended
			March 31		June 30		September 30			December 31
	Operating revenue			$223,830		$207,046		$183,213			$184,780
	Income (loss) from operations			48,552		16,613		(34,356	) (a)		(286,147) (b)
	Net income (loss)			25,943		4,444		(29,415	) (a)		(190,515) (b)
	Basic earnings (loss) per share			$0.52		$0.08		($0.54	)		($3.47)
	Diluted earnings (loss) per share			$0.52		$0.08		($0.54	)		($3.47)
			2013 Quarter Ended
			March 31		30-Jun		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 (c)
	Net income			40,758		39,022		36,102			1,752 (c)	(d)
	Basic earnings per share			$0.82		$0.78		$0.72			$0.04
	Diluted earnings per share			$0.82		$0.78		$0.72			$0.04
		(a)	Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).
		(b)	Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).
		(c)	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
		(d)	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

RECENTLY_ISSUED_ACCOUNTING_STA

RECENTLY ISSUED ACCOUNTING STANDARDS	12 Months Ended
	Dec. 31, 2014
Accounting Changes and Error Corrections [Abstract]
RECENTLY ISSUED ACCOUNTING STANDARDS	NOTE 19 – RECENTLY ISSUED ACCOUNTING STANDARDS:
	In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. The standard is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. Early application is not permitted. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. Although we are still evaluating the effect that this new standard may have on our financial statements and related disclosures, we do not anticipate that the implementation of this new standard will have a material effect.

GUARANTOR_FINANCIAL_STATEMENTS

GUARANTOR FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GUARANTOR FINANCIAL STATEMENTS	NOTE 20 – GUARANTOR FINANCIAL STATEMENTS:
	Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of the 2017 Convertible Notes and the 2022 Notes. Our other subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents consolidating financial information as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 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-14
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
				Subsidiary
						Guarantor
						Subsidiaries
	Assets
	Current assets:
	Cash and cash equivalents		$72,886		$1,450		$152		$  -		$74,488
	Restricted cash		177,647		-		-		-		177,647
	Accounts receivable		73,711		46,615		33		-		120,359
	Fair value of derivative contracts		-		139,179		-		-		139,179
	Current income tax receivable		7,212		-		-		-		7,212
	Deferred taxes *		4,095		-		-		(4,095)		-
	Inventory		1,011		2,698		-		-		3,709
	Other current assets		8,112		-		6		-		8,118
	Total current assets		344,674		189,942		191		(4,095)		530,712
	Oil and gas properties, full cost method:
	Proved		1,689,802		7,127,466		-		-		8,817,268
	Less: accumulated DD&A		(970,387)		(6,000,244)		-		-		(6,970,631)
	Net proved oil and gas properties		719,415		1,127,222		-		-		1,846,637
	Unevaluated		289,556		241,230		36,579		-		567,365
	Other property and equipment, net		32,340		-		-		-		32,340
	Fair value of derivative contracts		-		14,333		-		-		14,333
	Other assets, net		20,857		1,360		5,007		-		27,224
	Investment in subsidiary		1,050,546		-		41,638		(1,092,184)		-
	Total assets		$2,457,388		$1,574,087		$83,415		($1,096,279)		$3,018,611
	Liabilities and Stockholders’ Equity
	Current liabilities:
	Accounts payable to vendors		$74,756		$57,873		$    -		$  -		$132,629
	Undistributed oil and gas proceeds		22,158		1,074		-		-		23,232
	Accrued interest		9,022		-		-		-		9,022
	Deferred taxes *		-		24,214		-		(4,095)		20,119
	Asset retirement obligations		-		69,400		-		-		69,400
	Other current liabilities		49,306		199		-		-		49,505
	Total current liabilities		155,242		152,760		-		(4,095)		303,907
	Long-term debt		1,041,035		-		-		-		1,041,035
	Deferred taxes *		117,206		169,137		-		-		286,343
	Asset retirement obligations		3,588		243,421		-		-		247,009
	Other long-term liabilities		38,714		-		-		-		38,714
	Total liabilities		1,355,785		565,318		-		(4,095)		1,917,008
	Commitments and contingencies
	Stockholders’ equity:
	Common stock		549		-		-		-		549
	Treasury stock		(860)		-		-		-		(860)
	Additional paid-in capital		1,633,307		1,362,684		90,339		(1,453,023)		1,633,307
	Accumulated earnings (deficit)		(614,708)		(440,699)		12		440,687		(614,708)
	Accumulated other comprehensive income (loss)		83,315		86,784		(6,936)		(79,848)		83,315
	Total stockholders’ equity		1,101,603		1,008,769		83,415		(1,092,184)		1,101,603
	Total liabilities and stockholders’ equity		$2,457,388		$1,574,087		$83,415		($1,096,279)		$3,018,611
	* Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.
	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-13
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
						Guarantor
				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 derivative 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 derivative 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 derivative 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 derivative 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 STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2014
(In thousands)
	Parent		Guarantor		Non-		Eliminations		Consolidated
			Subsidiary		Guarantor
					Subsidiaries
Operating revenue:
Oil production		$29,701		$486,403		$   -		$   -		$516,104
Natural gas production		86,812		79,682		-		-		166,494
Natural gas liquids production		61,200		24,442		-		-		85,642
Other operational income		7,551		400		-		-		7,951
Derivative income, net		-		19,351		-		-		19,351
Total operating revenue		185,264		610,278		-		-		795,542
Operating expenses:
Lease operating expenses		18,719		157,776		-		-		176,495
Transportation, processing, and gathering expenses		53,028		11,923		-		-		64,951
Production taxes		8,324		3,827		-		-		12,151
Depreciation, depletion, amortization		138,313		201,693		-		-		340,006
Write-down of oil and gas properties		351,192		-		-		-		351,192
Accretion expense		230		28,181		-		-		28,411
Salaries, general and administrative		66,430		4		17		-		66,451
Incentive compensation expense		10,361		-		-		-		10,361
Other operational expenses		669		193		-		-		862
Total operating expenses		647,266		403,597		17		-		1,050,880
Income (loss) from operations		(462,002)		206,681		(17)		-		(255,338)
Other (income) expenses:
Interest expense		38,810		45		-		-		38,855
Interest income		(333)		(192)		(49)		-		(574)
Other income		(836)		(1,496)		-		-		(2,332)
Other expense		274		-		-		-		274
Income from investment in subsidiaries		(133,336)		-		(32)		133,368		-
Total other (income) expenses		(95,421)		(1,643)		(81)		133,368		36,223
Income (loss) before taxes		(366,581)		208,324		64		(133,368)		(291,561)
Provision (benefit) for income taxes:
Current		159		-		-		-		159
Deferred		(177,197)		75,020		-		-		(102,177)
Total income taxes		(177,038)		75,020		-		-		(102,018)
Net income (loss)		($189,543)		$133,304		$  64		($133,368)		($189,543)
Comprehensive income (loss)		($104,166)		$133,304		$  64		($133,368)		($104,166)
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
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
Natural 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 OPERATIONS
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
Natural 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 CASH FLOWS
YEAR ENDED DECEMBER 31, 2014
(In thousands)
	Parent		Guarantor		Non-		Eliminations		Consolidated
			Subsidiary
					Guarantor
					Subsidiaries
Cash flows from operating activities:
Net income (loss)		($189,543)		$133,304		$64		($133,368)		($189,543)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		138,313		201,693		-		-		340,006
Write-down of oil and gas properties		351,192		-		-		-		351,192
Accretion expense		230		28,181		-		-		28,411
Deferred income tax (benefit) provision		(177,197)		75,020		-		-		(102,177)
Settlement of asset retirement obligations		(201)		(56,208)		-		-		(56,409)
Non-cash stock compensation expense		11,325		-		-		-		11,325
Non-cash derivative income		-		(18,028)		-		-		(18,028)
Non-cash interest expense		16,661		-		-		-		16,661
Change in current income taxes		158		-		-		-		158
Non-cash income from investment in subsidiaries		(133,336)		-		(32)		133,368		-
Change in intercompany receivables/payables		114,056		(145,250)		31,194		-		-
(Increase) decrease in accounts receivable		1,131		50,514		(34)		-		51,611
Increase in other current assets		(6,238)		-		(6)		-		(6,244)
(Increase) decrease in inventory		2,415		(2,415)		-		-		-
Decrease in accounts payable		(662)		(2,757)		-		-		(3,419)
Decrease in other current liabilities		(16,946)		(2,206)		-		-		(19,152)
Other		(1,755)		(1,496)		-		-		(3,251)
Net cash provided by operating activities		109,603		260,352		31,186		-		401,141
Cash flows from investing activities:
Investment in oil and gas properties		(338,731)		(558,003)		(30,513)		-		(927,247)
Proceeds from sale of oil and gas properties, net of expenses		28,103		214,811		-		-		242,914
Investment in fixed and other assets		(10,182)		-		-		-		(10,182)
Change in restricted funds		(177,647)		-		(425)		-		(178,072)
Investment in subsidiaries		-		-		(31,696)		31,696		-
Net cash used in investing activities		(498,457)		(343,192)		(62,634)		31,696		(872,587)
Cash flows from financing activities:
Proceeds from issuance of common stock		225,999		-		-		-		225,999
Deferred financing costs		(3,371)		-		-		-		(3,371)
Equity proceeds from parent		-		-		31,696		(31,696)		-
Net payments for share-based compensation		(7,182)		-		-		-		(7,182)
Net cash provided by financing activities		215,446		-		31,696		(31,696)		215,446
Effect of exchange rate changes on cash		-		-		(736)		-		(736)
Net change in cash and cash equivalents		(173,408)		(82,840)		(488)		-		(256,736)
Cash and cash equivalents, beginning of period		246,294		84,290		640		-		331,224
Cash and cash equivalents, end of period		$72,886		$1,450		$152		$  -		$74,488
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2013
(In thousands)
	Parent		Guarantor		Non-		Eliminations		Consolidated
			Subsidiary
					Guarantor
					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-		Eliminations		Consolidated
			Subsidiary		Guarantor
					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

ORGANIZATION_AND_SUMMARY_OF_SI1

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
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. and Stone Energy Canada, U.L.C. 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, income 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 contracts, 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, 2014 and 2013, 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.
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 shareholders 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 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.
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, the computation of DD&A expense and the assessment of impairment of oil and gas properties. 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. Under the full cost method, oil and gas properties are subject to the ceiling test as discussed below while under the successful efforts method oil and gas properties are assessed for impairment in accordance with ASC 360.
	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 period reserves being determined by adding production to the end of 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 (adjusted for hedges and 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 net oil and gas properties 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 lives 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 considered 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 or underdelivered 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 and income tax purposes. For financial reporting purposes, all exploratory and development expenditures related to evaluated projects, including future abandonment costs, are capitalized and amortized using the UOP method. For income tax purposes, only the leasehold, geological and geophysical and equipment relative to successful wells are capitalized and recovered through DD&A, although for 2012, 2013 and 2014, 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 as a hedging instrument. Instruments that qualify as a hedging instrument, with contemporaneous documentation, are recorded as either an asset or liability, measured at fair value, with subsequent changes in the derivative’s fair value recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operating activities. Instruments not qualifying as hedging instruments 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 and derivative instruments not qualifying as hedging instruments are recognize in earnings through derivative expense (income) and cash flows from operating activities.
Share-Based Compensation	Share-Based Compensation:
	We record share-based compensation using 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, 2014
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,
		2014		2013		2012
	Income (numerator):
	Basic:
	Net income (loss)		($189,543)		$117,634		$149,426
	Net income attributable to participating securities		-		(2,817)		(2,984)
	Net income (loss) attributable to common stock - basic		($189,543)		$114,817		$146,422
	Diluted:
	Net income (loss)		($189,543)		$117,634		$149,426
	Net income attributable to participating securities		-		(2,815)		(2,982)
	Net income (loss) attributable to common stock - diluted		($189,543)		$114,819		$146,444
	Weighted average shares (denominator):
	Weighted average shares - basic		52,721		48,693		48,319
	Dilutive effect of stock options		-		42		42
	Weighted average shares - diluted		52,721		48,735		48,361
	Basic earnings (loss) per share		($3.60)		$2.36		$3.03
	Diluted earnings (loss) per share		($3.60)		$2.36		$3.03

ACCOUNTS_RECEIVABLE_Tables

ACCOUNTS RECEIVABLE (Tables)	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
Components of Accounts Receivable	Our accounts receivable are comprised of the following amounts:
		As of December 31,
		2014		2013
	Other co-venturers		$16,291		$13,904
	Trade		60,263		134,622
	Unbilled accounts receivable		33,052		22,001
	Other		10,753		1,444
	Total accounts receivable		$120,359		$171,971

CONCENTRATIONS_Tables

CONCENTRATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
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 indicated periods:
		Year Ended December 31,
		2014			2013			2012
	Conoco, Inc.		(a	)		(a	)		13	%
	Phillips 66 Company		31	%		35	%		18	%
	Shell Trading (US) Company		32	%		33	%		41	%
	(a)    Less than 10 percent.

DERIVATIVE_INSTRUMENTS_AND_HED1

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Hedging Positions	The following table illustrates our derivative positions for calendar years 2015 and 2016 as of February 24, 2015:
			Fixed-Price Swaps (NYMEX)
			Natural Gas								Oil
			Daily Volume				Swap Price				Daily Volume			Swap Price
			(MMBtus/d)				($/MMBtu)							($/Bbl)
											(Bbls/d)
	2015			10,000				4.005				1,000			89
	2015			10,000				4.12				1,000			90
	2015			10,000				4.15				1,000			90.25
	2015			10,000				4.165				1,000			90.4
	2015			10,000				4.22				1,000			91.05
	2015			10,000				4.255				1,000			93.28
	2015											1,000			93.37
	2015											1,000			94.85
	2015											1,000			95
	2016			10,000				4.11				1,000			90
	2016			10,000				4.12
Location and Fair Value Amounts of Derivative Instruments Reported in Balance Sheet	The following tables disclose the location and fair value amounts of derivatives qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2014 and 2013:
	Fair Value of Derivatives Qualifying as Hedging Instruments at December 31, 2014
			Asset Derivatives						Liability Derivatives
	Description		Balance Sheet Location		Fair Value				Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of derivative contracts			$127,033			Current liabilities: Fair value of derivative contracts			$  -
			Long-term assets: Fair value of derivative contracts			14,333			Long-term liabilities: Fair value of derivative contracts			-
						$141,366						$  -
	Fair Value of Derivatives Qualifying as Hedging 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 derivative contracts			$4,549			Current liabilities: Fair value of derivative contracts			$7,753
			Long-term assets: Fair value of derivative contracts			1,378			Long-term liabilities: Fair value of derivative contracts			470
						$5,927						$8,223
Before Tax Effect of Derivative Instruments in Statement of Operations	The following table discloses the before tax effect of derivatives qualifying as hedging instruments, as reported in the statement of operations, for the years ended December 31, 2014, 2013 and 2012:
	Effect of Derivatives Qualifying as Hedging Instruments on the Statement of Operations
	for the Years Ended December 31, 2014, 2013 and 2012
	Derivatives in Cash		Amount of Gain				Gain (Loss) Reclassified from						Gain (Loss) Recognized in Income
			(Loss) Recognized
	Flow Hedging		in Other				Accumulated Other Comprehensive Income						on Derivatives
			Comprehensive				into Income
	Relationships		Income on										(Ineffective Portion)
			Derivatives				(Effective Portion) (a)
							Location						Location
			2014						2014					2014
	Commodity contracts			$136,097			Operating revenue -			$526			Derivative income, net		$5,721
							oil/gas production
	Total			$136,097						$526					$5,721
			2013						2013					2013
	Commodity contracts			($26,945)			Operating revenue -			$20,289			Derivative expense, net		($2,090)
							oil/gas production
	Total			($26,945)						$20,289					($2,090)
			2012						2012					2012
	Commodity contracts			$41,209			Operating revenue -			$30,326			Derivative income, net		$3,428
							oil/gas production
	Total			$41,209						$30,326					$3,428
		(a)	For the year ended December 31, 2014, effective hedging contracts increased oil revenue by $7,929 and decreased gas revenue by $7,403. 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.
Location and Fair Value Amounts of Derivative Instruments Not Qualifying as Hedging Instruments Reported in Balance Sheet	The following table discloses the location and fair value amounts of our derivatives not qualifying as hedging instruments, as reported in our balance sheet, at December 31, 2014. All of our derivatives at December 31, 2013 qualified as hedging instruments.
	Fair Value of Derivatives Not Qualifying as Hedging Instruments at December 31, 2014
	Description		Balance Sheet Location		Fair Value
	Commodity contracts		Current assets: Fair value of derivative contracts		$	12,146
Gains or Losses Related to Changes in Fair Value and Cash Settlements on Derivatives Not Qualifying as Hedging Instruments	Gains or losses related to changes in fair value and cash settlements for derivatives not qualifying as hedging instruments are recorded as derivative income (expense) in the statement of operations. The following table discloses the before tax effect of our derivatives not qualifying as hedging instruments on the statement of operations for the year ended December 31, 2014:
	Amount of Gain Recognized in Derivative Income
	Description		Year Ended
			December 31, 2014
	Commodity contracts:
	Cash settlements			$1,484
	Change in fair value			12,146
	Total gains on non-qualifying hedges			$13,630
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 derivative contracts			$4,549				($4,043)				$506
	Long-term assets: Fair value of derivative contracts			1,378				(274)				1,104
	Current liabilities: Fair value of derivative contracts			(7,753)				4,043				(3,710)
	Long-term liabilities: Fair value of derivative contracts			(470)				274				(196)

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
		Fair Value Measurements at December 31, 2014
	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 (Other assets)		$8,425		$8,425		$  -		$  -
	Derivative contracts		153,512		-		153,512		-
	Total		$161,937		$8,425		$153,512		$  -
		Fair Value Measurements at December 31, 2014
	Liabilities	Total		Quoted Prices in		Significant Other		Significant
				Active Markets for		Observable		Unobservable
				Identical Liabilities		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
	Derivative contracts		$  -		$  -		$  -		$  -
	Total		$  -		$  -		$  -		$  -
	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 (Other assets)		$8,248		$8,248		$  -		$  -
	Derivative 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)
	Derivative contracts		$8,223		$  -		$8,223		$  -
	Total		$8,223		$  -		$8,223		$  -

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	The change in our asset retirement obligations during the years ended December 31, 2014, 2013 and 2012 is set forth below:
		Year Ended December 31,
		2014		2013		2012
	Asset retirement obligations as of the beginning of the year, including current portion		$502,513		$488,302		$425,779
	Liabilities incurred		28,606		19,043		3,869
	Liabilities settled		(55,839)		(79,695)		(67,641)
	Liabilities assumed		-		-		15,263
	Divestment of properties		(137,801)		(9,245)		(7,563)
	Accretion expense		28,411		33,575		33,331
	Revision of estimates		(49,481)		50,533		85,264
	Asset retirement obligations as of the end of the year, including current portion		$316,409		$502,513		$488,302

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Analysis of Deferred Taxes	An analysis of our deferred taxes follows:
		As of December 31,
		2014			2013
	Tax effect of temporary differences:
	Net operating loss carryforwards		$99,615			$24,437
	Oil and gas properties – full cost		(476,367)			(576,393)
	Asset retirement obligations		113,907			180,905
	Stock compensation		5,603			5,537
	Hedges		(54,439)			826
	Accrued incentive compensation		6,185			9,189
	Other		(966)			(3,484)
			($306,462)			($358,983)
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,
		2014		2013	2012
	Income tax expense computed at the statutory federal income tax rate	35.0%		35.0%	35.0%
	State taxes	1.0		1.0	1.0
	IRC Sec. 162(m) limitation	(0.5)		0.8	0.6
	Tax deficits on stock compensation	(0.2)		-	-
	Other	(0.3)		0.1	(0.5)
	Effective income tax rate	35.0%		36.9%	36.1%

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt consisted of the following at:
		December 31,
		2014		2013
	1 3⁄4% Senior Convertible Notes due 2017		$266,035		$252,084
	7 1⁄2% Senior Notes due 2022		775,000		775,000
	Bank debt		-		-
	Total long-term debt		$1,041,035		$1,027,084

ACCUMULATED_OTHER_COMPREHENSIV1

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule of Changes in Accumulated Other Comprehensive Income Loss	Changes in accumulated other comprehensive income (loss) by component for the years ended December 31, 2014 and 2013 were as follows:
		Cash Flow		Foreign		Total
		Hedges		Currency
				Items
	For the Year Ended December 31, 2014
	Beginning balance, net of tax		($1,395)		($667)		($2,062)
	Other comprehensive income (loss) before reclassifications:
	Change in fair value of derivatives		136,097		-		136,097
	Foreign currency translations		-		(2,801)		(2,801)
	Income tax effect		(48,995)		-		(48,995)
	Net of tax		87,102		(2,801)		84,301
	Amounts reclassified from accumulated other comprehensive income:
	Operating revenue: oil/gas production		526		-		526
	Derivative expense, net		(2,208)		-		(2,208)
	Income tax effect		606		-		606
	Net of tax		(1,076)		-		(1,076)
	Other comprehensive income (loss), net of tax		88,178		(2,801)		85,377
	Ending balance, net of tax		$86,783		($3,468)		$83,315
		Cash Flow		Foreign		Total
		Hedges		Currency
				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 loss, net of tax		(30,228)		(667)		(30,895)
	Ending balance, net of tax		($1,395)		($667)		($2,062)
	In 2012, the only component of accumulated other comprehensive income related to our cash flow hedges. Changes in accumulated other comprehensive income for the year ended December 31, 2012 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

SHAREBASED_COMPENSATION_Tables

SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based 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, 2014 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		331,174		$39.37
	Granted		-		-
	Exercised		(250)		46.20
	Forfeited		-		-
	Expired		(125,950)		48.21
	Options outstanding, end of period		204,974		33.94		2.4 years		$531
	Options exercisable, end of period		204,974		33.94		2.4 years		531
	Options unvested, end of period		-		-		-		-
	Exercise prices for stock options outstanding at December 31, 2014 range from $6.97 to $53.20.
	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
	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		41.00		2.5 years		459
	Options unvested, end of period		33,790		17.17		5.4 years		307
Summary of Restricted Stock Activity Under Plan	A summary of the restricted stock activity under the 2009 Plan for the years ended December 31, 2014, 2013 and 2012 is as follows (amounts in table represent actual values):
		2014				2013				2012
		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		1,258,053		$23.92		1,108,874		$27.56		923,740		$20.08
	Issuances		674,904		36.44		848,498		20.61		670,818		31.43
	Lapse of restrictions		(598,796)		24.57		(534,041)		25.45		(462,141)		18.29
	Forfeitures		(31,055)		30.19		(165,278)		26.43		(23,543)		26.10
	Restricted stock outstanding, end of period		1,303,106		$29.95		1,258,053		$23.92		1,108,874		$27.56

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 were as follows:
	2015	$	1,416
	2016		1,571
	2017		1,524
	2018		1,339
	2019		1,194
	2020		1,206
	2021		879
	2022		779
	2023		792
	2024		805
	2025		474

SUPPLEMENTAL_INFORMATION_ON_OI1

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2014
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,
	Unevaluated oil and gas properties – United States:	2014		2013		2012
	Net costs incurred (evaluated) during year:
	Acquisition costs		($42,384)		$30,271		$9,739
	Exploration costs		(186,308)		188,830		(1,209)
	Capitalized interest		45,722		46,860		37,656
			($182,970)		$265,961		$46,186
Financial Data Associated with Unevaluated Costs	The following table discloses financial data associated with unevaluated costs (United States and Canada) at December 31, 2014:
		Balance as of		Net Costs Incurred During the
		December 31,		Year Ended December 31,
		2014		2014		2013		2012		2011
										and prior
	Acquisition costs		$285,896		$7,330		$82,990		$24,736		$170,840
	Exploration costs		167,510		66,512		78,684		5,318		16,996
	Capitalized interest		113,959		22,352		36,137		21,993		33,477
	Total unevaluated costs		$567,365		$96,194		$197,811		$52,047		$221,313
Summary of Estimated Proved Oil and Natural Gas Reserve	Estimated proved oil, natural gas and NGL reserves at December 31, 2014, 2013 and 2012 are prepared in accordance with the SEC’s rule, “Modernization of Oil and Gas Reporting,” using a historical 12-month average pricing assumption.
		Oil		NGLs		Natural		Oil,
		(MBbls)		(MBbls)		Gas		Natural
						(MMcf)		Gas and
								NGLs
								(MMcfe)
	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
	Revisions of previous estimates		(624)		(331)		(4,631)		(10,362)
	Extensions, discoveries and other additions		9,650		7,521		131,617		234,639
	Sale of reserves		(4,888)		(556)		(46,483)		(79,151)
	Production		(5,568)		(2,114)		(47,426)		(93,515)
	Estimated proved reserves as of December 31, 2014		42,397		27,817		493,843		915,124
	Estimated proved developed reserves:
	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
	as of December 31, 2014		22,957		13,743		249,924		470,118
	Estimated proved undeveloped reserves:
	as of December 31, 2012		15,913		9,473		184,418		336,745
	as of December 31, 2013		15,907		11,728		213,820		379,628
	as of December 31, 2014		19,440		14,074		243,919		445,006
Summary of Standardized Measure of Discounted Future Net Cash Flows	Standardized Measure
	Year Ended December 31,
		2014		2013		2012
	Future cash inflows		$  6,635,751		$  7,040,928		$  6,295,455
	Future production costs		(2,413,004)		(2,062,657)		(1,946,426)
	Future development costs		(1,511,687)		(1,431,101)		(1,241,531)
	Future income taxes		(609,516)		(884,637)		(799,007)
	Future net cash flows		2,101,544		2,662,533		2,308,491
	10% annual discount		(682,752)		(977,531)		(794,632)
	Standardized measure of discounted future net cash flows		$  1,418,792		$  1,685,002		$  1,513,859
		Changes in Standardized Measure
		Year Ended December 31,
		2014		2013		2012
	Standardized measure at beginning of year		$1,685,002		$1,513,859		$1,542,962
	Sales and transfers of oil, gas and NGLs produced, net of production costs		(486,232)		(708,017)		(697,741)
	Changes in price, net of future production costs		(864,118)		229,425		(380,841)
	Extensions and discoveries, net of future production and development costs		549,649		155,592		178,272
	Changes in estimated future development costs, net of development costs incurred during the period		203,026		28,684		212,329
	Revisions of quantity estimates		(27,495)		281,558		76,450
	Accretion of discount		222,009		202,087		207,292
	Net change in income taxes		209,323		(28,084)		22,947
	Purchases of reserves in-place		-		-		276,389
	Sales of reserves in-place		(152,787)		15,531		2,480
	Changes in production rates due to timing and other		80,415		(5,633)		73,320
	Net increase (decrease) in standardized measure		(266,210)		171,143		(29,103)
	Standardized measure at end of year		$1,418,792		$1,685,002		$1,513,859
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,
		2014		2013		2012
	Oil and gas properties – United States, proved and unevaluated:
	Balance, beginning of year		$8,517,873		$7,692,261		$7,049,777
	Costs incurred during the year (capitalized):
	Acquisition costs, net of sales of unevaluated properties		44,634		70,903		102,807
	Exploratory costs		270,850		297,113		81,458
	Development costs (1)		438,334		378,242		395,555
	Salaries, general and administrative costs		33,975		32,815		25,318
	Interest		45,722		46,860		37,656
	Less: overhead reimbursements		(3,334)		(321)		(310)
	Total costs incurred during the year, net of divestitures		830,181		825,612		642,484
	Balance, end of year		$9,348,054		$8,517,873		$7,692,261
	Accumulated DD&A:
	Balance, beginning of year		($5,908,760)		($5,510,166)		($5,174,729)
	Provision for DD&A		(335,987)		(346,827)		(341,096)
	Write-down of oil and gas properties		(351,192)		-		-
	Sale of proved properties		(374,692)		(51,767)		5,659
	Balance, end of year		($6,970,631)		($5,908,760)		($5,510,166)
	Net capitalized costs – United States, proved and unevaluated		$2,377,423		$2,609,113		$2,182,095
	DD&A per Mcfe		$3.59		$3.43		$3.69
	(1) Includes capitalized asset retirement costs of ($20,305), $54,737 and $95,293, respectively.
	Costs incurred during the year (expensed):
	Lease operating expenses		$176,495		$201,153		$215,003
	Transportation, processing and gathering expenses		64,951		42,172		21,782
	Production taxes		12,151		15,029		10,015
	Accretion expense		28,411		33,575		33,331
	Expensed costs – United States		$282,008		$291,929		$280,131
Canada [Member]
Financial Data Relative to Oil and Gas Producing Activities	The following table discloses certain financial data relative to our oil and gas activities located in Canada:
		Year Ended December 31,
		2014		2013
	Oil and gas properties – Canada, unevaluated:
	Balance, beginning of year		$10,583		$  -
	Costs incurred during the year (capitalized):
	Acquisition costs		6,956		8,764
	Exploratory costs		19,040		1,819
	Total costs incurred during the year		25,996		10,583
	Balance, end of year, unevaluated		$36,579		$10,583

SUMMARIZED_QUARTERLY_FINANCIAL1

SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Results of Operations by Quarter	The results of operations by quarter are as follows:
			2014 Quarter Ended
			March 31		June 30		September 30			December 31
	Operating revenue			$223,830		$207,046		$183,213			$184,780
	Income (loss) from operations			48,552		16,613		(34,356	) (a)		(286,147) (b)
	Net income (loss)			25,943		4,444		(29,415	) (a)		(190,515) (b)
	Basic earnings (loss) per share			$0.52		$0.08		($0.54	)		($3.47)
	Diluted earnings (loss) per share			$0.52		$0.08		($0.54	)		($3.47)
			2013 Quarter Ended
			March 31		30-Jun		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 (c)
	Net income			40,758		39,022		36,102			1,752 (c)	(d)
	Basic earnings per share			$0.82		$0.78		$0.72			$0.04
	Diluted earnings per share			$0.82		$0.78		$0.72			$0.04
		(a)	Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).
		(b)	Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).
		(c)	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
		(d)	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, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Balance Sheet	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-14
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
				Subsidiary
						Guarantor
						Subsidiaries
	Assets
	Current assets:
	Cash and cash equivalents		$72,886		$1,450		$152		$  -		$74,488
	Restricted cash		177,647		-		-		-		177,647
	Accounts receivable		73,711		46,615		33		-		120,359
	Fair value of derivative contracts		-		139,179		-		-		139,179
	Current income tax receivable		7,212		-		-		-		7,212
	Deferred taxes *		4,095		-		-		(4,095)		-
	Inventory		1,011		2,698		-		-		3,709
	Other current assets		8,112		-		6		-		8,118
	Total current assets		344,674		189,942		191		(4,095)		530,712
	Oil and gas properties, full cost method:
	Proved		1,689,802		7,127,466		-		-		8,817,268
	Less: accumulated DD&A		(970,387)		(6,000,244)		-		-		(6,970,631)
	Net proved oil and gas properties		719,415		1,127,222		-		-		1,846,637
	Unevaluated		289,556		241,230		36,579		-		567,365
	Other property and equipment, net		32,340		-		-		-		32,340
	Fair value of derivative contracts		-		14,333		-		-		14,333
	Other assets, net		20,857		1,360		5,007		-		27,224
	Investment in subsidiary		1,050,546		-		41,638		(1,092,184)		-
	Total assets		$2,457,388		$1,574,087		$83,415		($1,096,279)		$3,018,611
	Liabilities and Stockholders’ Equity
	Current liabilities:
	Accounts payable to vendors		$74,756		$57,873		$    -		$  -		$132,629
	Undistributed oil and gas proceeds		22,158		1,074		-		-		23,232
	Accrued interest		9,022		-		-		-		9,022
	Deferred taxes *		-		24,214		-		(4,095)		20,119
	Asset retirement obligations		-		69,400		-		-		69,400
	Other current liabilities		49,306		199		-		-		49,505
	Total current liabilities		155,242		152,760		-		(4,095)		303,907
	Long-term debt		1,041,035		-		-		-		1,041,035
	Deferred taxes *		117,206		169,137		-		-		286,343
	Asset retirement obligations		3,588		243,421		-		-		247,009
	Other long-term liabilities		38,714		-		-		-		38,714
	Total liabilities		1,355,785		565,318		-		(4,095)		1,917,008
	Commitments and contingencies
	Stockholders’ equity:
	Common stock		549		-		-		-		549
	Treasury stock		(860)		-		-		-		(860)
	Additional paid-in capital		1,633,307		1,362,684		90,339		(1,453,023)		1,633,307
	Accumulated earnings (deficit)		(614,708)		(440,699)		12		440,687		(614,708)
	Accumulated other comprehensive income (loss)		83,315		86,784		(6,936)		(79,848)		83,315
	Total stockholders’ equity		1,101,603		1,008,769		83,415		(1,092,184)		1,101,603
	Total liabilities and stockholders’ equity		$2,457,388		$1,574,087		$83,415		($1,096,279)		$3,018,611
	* Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.
	CONDENSED CONSOLIDATING BALANCE SHEET
	31-Dec-13
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
						Guarantor
				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 derivative 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 derivative 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 derivative 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 derivative 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 Statement of Operations	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	YEAR ENDED DECEMBER 31, 2014
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
				Subsidiary		Guarantor
						Subsidiaries
	Operating revenue:
	Oil production		$29,701		$486,403		$   -		$   -		$516,104
	Natural gas production		86,812		79,682		-		-		166,494
	Natural gas liquids production		61,200		24,442		-		-		85,642
	Other operational income		7,551		400		-		-		7,951
	Derivative income, net		-		19,351		-		-		19,351
	Total operating revenue		185,264		610,278		-		-		795,542
	Operating expenses:
	Lease operating expenses		18,719		157,776		-		-		176,495
	Transportation, processing, and gathering expenses		53,028		11,923		-		-		64,951
	Production taxes		8,324		3,827		-		-		12,151
	Depreciation, depletion, amortization		138,313		201,693		-		-		340,006
	Write-down of oil and gas properties		351,192		-		-		-		351,192
	Accretion expense		230		28,181		-		-		28,411
	Salaries, general and administrative		66,430		4		17		-		66,451
	Incentive compensation expense		10,361		-		-		-		10,361
	Other operational expenses		669		193		-		-		862
	Total operating expenses		647,266		403,597		17		-		1,050,880
	Income (loss) from operations		(462,002)		206,681		(17)		-		(255,338)
	Other (income) expenses:
	Interest expense		38,810		45		-		-		38,855
	Interest income		(333)		(192)		(49)		-		(574)
	Other income		(836)		(1,496)		-		-		(2,332)
	Other expense		274		-		-		-		274
	Income from investment in subsidiaries		(133,336)		-		(32)		133,368		-
	Total other (income) expenses		(95,421)		(1,643)		(81)		133,368		36,223
	Income (loss) before taxes		(366,581)		208,324		64		(133,368)		(291,561)
	Provision (benefit) for income taxes:
	Current		159		-		-		-		159
	Deferred		(177,197)		75,020		-		-		(102,177)
	Total income taxes		(177,038)		75,020		-		-		(102,018)
	Net income (loss)		($189,543)		$133,304		$  64		($133,368)		($189,543)
	Comprehensive income (loss)		($104,166)		$133,304		$  64		($133,368)		($104,166)
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	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
	Natural 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 OPERATIONS
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
Natural 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 Cash Flows	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2014
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
				Subsidiary
						Guarantor
						Subsidiaries
	Cash flows from operating activities:
	Net income (loss)		($189,543)		$133,304		$64		($133,368)		($189,543)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion and amortization		138,313		201,693		-		-		340,006
	Write-down of oil and gas properties		351,192		-		-		-		351,192
	Accretion expense		230		28,181		-		-		28,411
	Deferred income tax (benefit) provision		(177,197)		75,020		-		-		(102,177)
	Settlement of asset retirement obligations		(201)		(56,208)		-		-		(56,409)
	Non-cash stock compensation expense		11,325		-		-		-		11,325
	Non-cash derivative income		-		(18,028)		-		-		(18,028)
	Non-cash interest expense		16,661		-		-		-		16,661
	Change in current income taxes		158		-		-		-		158
	Non-cash income from investment in subsidiaries		(133,336)		-		(32)		133,368		-
	Change in intercompany receivables/payables		114,056		(145,250)		31,194		-		-
	(Increase) decrease in accounts receivable		1,131		50,514		(34)		-		51,611
	Increase in other current assets		(6,238)		-		(6)		-		(6,244)
	(Increase) decrease in inventory		2,415		(2,415)		-		-		-
	Decrease in accounts payable		(662)		(2,757)		-		-		(3,419)
	Decrease in other current liabilities		(16,946)		(2,206)		-		-		(19,152)
	Other		(1,755)		(1,496)		-		-		(3,251)
	Net cash provided by operating activities		109,603		260,352		31,186		-		401,141
	Cash flows from investing activities:
	Investment in oil and gas properties		(338,731)		(558,003)		(30,513)		-		(927,247)
	Proceeds from sale of oil and gas properties, net of expenses		28,103		214,811		-		-		242,914
	Investment in fixed and other assets		(10,182)		-		-		-		(10,182)
	Change in restricted funds		(177,647)		-		(425)		-		(178,072)
	Investment in subsidiaries		-		-		(31,696)		31,696		-
	Net cash used in investing activities		(498,457)		(343,192)		(62,634)		31,696		(872,587)
	Cash flows from financing activities:
	Proceeds from issuance of common stock		225,999		-		-		-		225,999
	Deferred financing costs		(3,371)		-		-		-		(3,371)
	Equity proceeds from parent		-		-		31,696		(31,696)		-
	Net payments for share-based compensation		(7,182)		-		-		-		(7,182)
	Net cash provided by financing activities		215,446		-		31,696		(31,696)		215,446
	Effect of exchange rate changes on cash		-		-		(736)		-		(736)
	Net change in cash and cash equivalents		(173,408)		(82,840)		(488)		-		(256,736)
	Cash and cash equivalents, beginning of period		246,294		84,290		640		-		331,224
	Cash and cash equivalents, end of period		$72,886		$1,450		$152		$  -		$74,488
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2013
	(In thousands)
		Parent		Guarantor		Non-		Eliminations		Consolidated
				Subsidiary
						Guarantor
						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-		Eliminations		Consolidated
			Subsidiary		Guarantor
					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

Recovered_Sheet1

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Mar. 06, 2012
Building [Member]
Schedule Of Significant Accounting Policies [Line Items]
Estimated useful life of building	39 years
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%	1.75%	1.75%

Earnings_Per_Share_Calculation

Earnings Per Share - 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, 2014		Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Basic:
Net income (loss)	($190,515)	[1]	($29,415)	[2]	$4,444	$25,943	$1,752	[3],[4]	$36,102	$39,022	$40,758	($189,543)	$117,634	$149,426
Net income attributable to participating securities													-2,817	-2,984
Net income (loss) attributable to common stock - basic												-189,543	114,817	146,422
Diluted:
Net income (loss)	-190,515	[1]	-29,415	[2]	4,444	25,943	1,752	[3],[4]	36,102	39,022	40,758	-189,543	117,634	149,426
Net income attributable to participating securities													-2,815	-2,982
Net income (loss) attributable to common stock - diluted												($189,543)	$114,819	$146,444
Weighted average shares (denominator):
Weighted average shares - basic												52,721	48,693	48,319
Dilutive effect of stock options													42	42
Weighted average shares - diluted												52,721	48,735	48,361
Basic earnings (loss) per share	($3.47)		($0.54)		$0.08	$0.52	$0.04		$0.72	$0.78	$0.82	($3.60)	$2.36	$3.03
Diluted earnings (loss) per share	($3.47)		($0.54)		$0.08	$0.52	$0.04		$0.72	$0.78	$0.82	($3.60)	$2.36	$3.03
[1]	Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).
[2]	Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).
[3]	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
[4]	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			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	31-May-14
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Antidilutive stock options outstanding	205,000	242,000	347,000
Shares of common stock issued upon vesting of restricted stock	384,000	358,000	316,000
IPO [Member]
Weighted Average Shares Used In Computing Earnings Per Share [Line Items]
Common stock issued				5,750,000

Common_Stock_Offering_Addition

Common Stock Offering - Additional Information (Detail) (USD $)	12 Months Ended	1 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	31-May-14
Subsidiary, Sale of Stock [Line Items]
Net proceeds of stock after deducting underwriting discount	$225,999
IPO [Member]
Subsidiary, Sale of Stock [Line Items]
Common stock issued		5,750,000
Price of common stock		$41
Net proceeds of stock after deducting underwriting discount		$225,999

Accounts_Receivable_Components

Accounts Receivable - Components of Accounts Receivable (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Receivables [Abstract]
Other co-venturers	$16,291	$13,904
Trade	60,263	134,622
Unbilled accounts receivable	33,052	22,001
Other	10,753	1,444
Total accounts receivable	$120,359	$171,971

Concentrations_Customers_from_

Concentrations - Customers from Whom We Derived 10% or More of Total Oil and Gas Revenue (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Conoco, Inc [Member]
Concentration Risk [Line Items]
Concentration risk, benchmark description	Less than 10%	Less than 10%
Customer Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Conoco, Inc [Member]
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived			13.00%
Customer Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Phillips 66 Company [Member]
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	31.00%	35.00%	18.00%
Customer Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Shell Trading (US) Company [Member]
Concentration Risk [Line Items]
Customers from whom 10% or more revenue derived	32.00%	33.00%	41.00%

Concentrations_Additional_Info

Concentrations - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Unusual Risk or Uncertainty [Line Items]
Maximum amount of credit risk exposure	31,929
GOM Deep Water, Conventional Shelf and Deep Gas Properties [Member]
Unusual Risk or Uncertainty [Line Items]
Production associated with properties	60.00%
Estimated proved reserves derived	42.00%
Appalachian Properties [Member]
Unusual Risk or Uncertainty [Line Items]
Production associated with properties	40.00%
Estimated proved reserves derived	58.00%

Divestitures_Additional_Inform

Divestitures - Additional Information (Detail) (USD $)	12 Months Ended			1 Months Ended	0 Months Ended	1 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 31, 2014	Jan. 16, 2014	Oct. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest cash consideration	$242,914	$48,821	$403
Percentage of estimated proved oil and natural gas reserves		9.00%
GOM Conventional Shelf [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Estimates asset retirement obligations				125,198
Cash consideration received on sale of interest				177,647
Cut Off and Clovelly Fields [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest cash consideration					44,804
Estimates asset retirement obligations					9,162
Other Non Core Fields [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest cash consideration	26,065
Estimates asset retirement obligations	3,440
Percentage of estimated proved oil and natural gas reserves		2.00%
Weeks Island Field [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of interest cash consideration						42,957
Estimates asset retirement obligations						9,245
Gain or loss recognized from the sale of interest						$0

Recovered_Sheet2

Derivative Instruments and Hedging Activities - Hedging Positions (Detail)	Dec. 31, 2014
	MBbls
Oil (MBbls) [Member] | 2015 Hedging Position One [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	89
Oil (MBbls) [Member] | 2015 Hedging Position Two [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	90
Oil (MBbls) [Member] | 2015 Hedging Position Three [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	90.25
Oil (MBbls) [Member] | 2015 Hedging Position Four [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	90.4
Oil (MBbls) [Member] | 2015 Hedging Position Five [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	91.05
Oil (MBbls) [Member] | 2015 Hedging Position Six [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	93.28
Oil (MBbls) [Member] | 2015 Hedging Position Seven [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	93.37
Oil (MBbls) [Member] | 2015 Hedging Position Eight [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	94.85
Oil (MBbls) [Member] | 2015 Hedging Position Nine [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	95
Oil (MBbls) [Member] | 2016 Hedging Position One [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	1,000
Swap Price	90
Natural Gas (MMcfe) [Member] | 2015 Hedging Position One [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.005
Natural Gas (MMcfe) [Member] | 2015 Hedging Position Two [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.12
Natural Gas (MMcfe) [Member] | 2015 Hedging Position Three [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.15
Natural Gas (MMcfe) [Member] | 2015 Hedging Position Four [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.165
Natural Gas (MMcfe) [Member] | 2015 Hedging Position Five [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.22
Natural Gas (MMcfe) [Member] | 2015 Hedging Position Six [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.255
Natural Gas (MMcfe) [Member] | 2016 Hedging Position One [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.11
Natural Gas (MMcfe) [Member] | 2016 Hedging Position Two [Member]
Derivatives, Fair Value [Line Items]
Daily Volume	10,000
Swap Price	4.12

Recovered_Sheet3

Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended	1 Months Ended	4 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Aug. 31, 2014	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
			Contract	Contract	Contract
Derivative Instruments, Gain (Loss) [Line Items]
Maximum correlation between price of oil & natural gas in market and underlying price basis indicative in the derivative contract	100.00%	100.00%		100.00%
Accumulated other comprehensive income	$83,315	$83,315		83,315		($2,062)	$28,833
Accumulated other comprehensive income, to be reclassified into earnings in the next twelve months		77,991
Fair Value of Derivative Instruments, Assets Effect of Netting	0
Cash Flow Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income	$86,783	$86,783		86,783		($1,395)	$28,833	$21,868
Natural Gas (MMcfe) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of Contracts no longer qualifying as cash flow hedges			3	4
Scenario, Forecast [Member] | Natural Gas (MMcfe) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of Contracts no longer qualifying as cash flow hedges					3

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities - Location and Fair Value Amounts of Derivative Instruments Reported in Balance Sheet (Detail) (Commodity Contracts [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset Derivatives
Fair Value of Derivative Instruments, Assets	$141,366	$5,927
Liability Derivatives
Fair Value of Derivative Instruments, Liabilities		8,223
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	127,033	4,549
Long-term assets [Member]
Asset Derivatives
Fair Value of Derivative Instruments, Assets	$14,333	$1,378

Derivative_Instruments_and_Hed3

Derivative Instruments and Hedging Activities - 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, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion, Net, Total	$136,097	($26,945)	$41,209
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net, Total	526	20,289	30,326
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net, Total	5,721	-2,090	3,428
Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion, Net, Total	136,097	-26,945	41,209
Derivative income, 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	5,721	-2,090	3,428
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	$526	$20,289	$30,326

Derivative_Instruments_and_Hed4

Derivative Instruments and Hedging Activities - Before Tax Effect of Derivative Instruments in Statement of Operations (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Decrease/increase in oil revenue owing to effective hedging contracts	$7,929	$3,520	$8,546
Decrease/increase in gas revenue owing to effective hedging contracts	$7,403	$16,769	$21,780

Derivative_Instruments_and_Hed5

Derivative Instruments and Hedging Activities - Location and Fair Value Amounts of Derivative Instruments Not Qualifying as Hedging Instruments Reported in Balance Sheet (Detail) (Commodity Contracts [Member], Current Assets [Member], USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commodity Contracts [Member] | Current Assets [Member]
Asset Derivatives
Fair Value of Derivative Instruments	$12,146

Derivative_Instruments_and_Hed6

Derivative Instruments and Hedging Activities - Gains or Losses Related to Changes in Fair Value and Cash Settlements on Derivatives Not Qualifying as Hedging Instruments (Detail) (Commodity Contracts [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Cash settlements on Derivative Instruments not Qualifying Hedges	$1,484
Change in fair value on Derivative Instruments not Qualifying Hedges	12,146
Total gains on Derivative Instruments not Qualifying Hedges	$13,630

Derivative_Instruments_and_Hed7

Derivative Instruments and Hedging Activities - Impact of Rights of Offset Associated with Recognized Assets and Liabilities (Detail) (USD $)	0 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments And Hedging Activities [Line Items]
Fair Value of Derivative Instruments, Assets Effect of Netting	$0
Current Asset [Member]
Derivative Instruments And Hedging Activities [Line Items]
Fair Value of Derivative Instruments, Assets With Effects of Netting		4,549
Fair Value of Derivative Instruments, Assets Effect of Netting		-4,043
Fair Value of Derivative Instruments, Assets Without Netting		506
Long-term assets [Member]
Derivative Instruments And Hedging Activities [Line Items]
Fair Value of Derivative Instruments, Assets With Effects of Netting		1,378
Fair Value of Derivative Instruments, Assets Effect of Netting		-274
Fair Value of Derivative Instruments, Assets Without Netting		1,104
Current liabilities [Member]
Derivative Instruments And Hedging Activities [Line Items]
Fair Value of Derivative Instruments, Liabilities With Effects of Netting		-7,753
Fair Value of Derivative Instruments, Liabilities Effect of Netting		4,043
Fair Value of Derivative Instruments, Liabilities Without Netting		-3,710
Long-term liabilities [Member]
Derivative Instruments And Hedging Activities [Line Items]
Fair Value of Derivative Instruments, Liabilities With Effects of Netting		-470
Fair Value of Derivative Instruments, Liabilities Effect of Netting		274
Fair Value of Derivative Instruments, Liabilities Without Netting		($196)

Fair_Value_Measurements_Assets

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Marketable securities (Other assets)	$8,425	$8,248
Assets, Fair Value, Total	161,937	14,175
Liabilities, Fair Value, Total		8,223
Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value	153,512	5,927
Derivative Liabilities, Fair Value		8,223
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 (Other assets)	8,425	8,248
Assets, Fair Value, Total	8,425	8,248
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value, Total	153,512	5,927
Liabilities, Fair Value, Total		8,223
Significant Other Observable Inputs (Level 2) [Member] | Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value	153,512	5,927
Derivative Liabilities, Fair Value		$8,223

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Convertible Notes Due 2017 [Member]
Debt Instrument [Line Items]
Fair value of Convertible Notes	$252,587	$260,377
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Fair value of Notes	$664,563	$814,719

Asset_Retirement_Obligations_C

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations as of the beginning of the year, including current portion	$502,513	$488,302	$425,779
Liabilities incurred	28,606	19,043	3,869
Liabilities settled	-55,839	-79,695	-67,641
Liabilities assumed			15,263
Divestment of properties	-137,801	-9,245	-7,563
Accretion expense	28,411	33,575	33,331
Revision of estimates	-49,481	50,533	85,264
Asset retirement obligations as of the end of the year, including current portion	$316,409	$502,513	$488,302

Income_Taxes_Analysis_of_Defer

Income Taxes - Analysis of Deferred Taxes (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Tax effect of temporary differences:
Net operating loss carryforwards	$99,615	$24,437
Oil and gas properties - full cost	-476,367	-576,393
Asset retirement obligations	113,907	180,905
Stock compensation	5,603	5,537
Hedges	-54,439	826
Accrued incentive compensation	6,185	9,189
Other	-966	-3,484
Deferred Tax Assets, Net, Total	($306,462)	($358,983)

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current federal income tax benefit	$159	($10,904)	$15,022
Current income tax receivable	7,212	7,366
Operating loss carryforwards	281,240
Operating loss carryforwards begins to expire	2033
Operating loss carryforwards expiration year	2034
Statutory depletion deductions available for tax reporting purposes	920
Income taxes allocated to other comprehensive income related to oil and gas hedges	49,601	-17,003	3,918
Unrecognized tax benefits, interest expense	$0	$0

Income_Taxes_Reconciliation_Be

Income Taxes - 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, 2014	Dec. 31, 2013	Dec. 31, 2012
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	-0.50%	0.80%	0.60%
Tax deficits on stock compensation	-0.20%
Other	-0.30%	0.10%	-0.50%
Effective income tax rate	35.00%	36.90%	36.10%

LongTerm_Debt_LongTerm_Debt_De

Long-Term Debt - Long-Term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Long-term debt	$1,041,035	$1,027,084
1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Long-term debt	266,035	252,084
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	775,000	775,000
Bank debt [Member]
Debt Instrument [Line Items]
Long-term debt	$0

LongTerm_Debt_LongTerm_Debt_Pa

Long-Term Debt - Long-Term Debt (Parenthetical) (Detail)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Interest rate	1.75%	1.75%	1.75%
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Interest rate	7.50%	7.50%

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 27, 2013	Nov. 08, 2012	Feb. 24, 2015	Oct. 31, 2014	Jun. 24, 2014	Mar. 06, 2012
Debt Instrument [Line Items]
Proceeds from sale of warrants			$40,170,000
Liability component of convertible note	1,041,035,000	1,027,084,000
Proceeds from issuance of senior notes		489,250,000	300,000,000
Effective interest rates	7.51%	7.75%	7.04%
Accrued interest payment	9,022,000	9,022,000
Deferred financing costs, net of accumulated amortization	12,415,000	11,754,000
Total interest cost incurred	84,577,000	79,697,000	68,031,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Outstanding borrowing under bank credit facility	480,779,000
Subsequent Event [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Outstanding borrowing under bank credit facility						480,779,000
Minimum [Member]
Debt Instrument [Line Items]
Percentage of borrowing base utilization	1.50%
Maximum [Member]
Debt Instrument [Line Items]
Percentage of borrowing base utilization	2.50%
Bank debt [Member]
Debt Instrument [Line Items]
Credit facility initial date	24-Jun-14
Redetermined base borrowing and credit facility								900,000,000
Maturity of new credit facility if note issue under 2004 indenture are retired on or before April 15, 2014	1-Jul-19
Initial bank and availability under facility	0						500,000,000	500,000,000
Outstanding borrowing under bank credit facility	19,221,000
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
Debt to EBITDA ratio, as defined in credit agreement	not greater than 3.75 for preceding four quarter
EBITDA to consolidated net interest, as defined in credit agreement	not less than 2.5 for preceding four quarter
Debt to EBITDA ratio	2.26 to 1
EBITDA to consolidated net interest ratio	12.03 to 1
Liability component of convertible note	0
Bank debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Initial bank and availability under facility						0
Outstanding borrowing under bank credit facility						480,779,000
1.75% Senior Convertible Notes due 2017 [Member]
Debt Instrument [Line Items]
Aggregate principal amount of senior notes			300,000,000						300,000,000
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	0.0234449
Principal amount of 2017 convertible notes	$1
Initial conversion price of convertible note 2017	$42.65
Closing share price	$16.88
Convertible notes principal amount	1,000
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	70,830,000
Anti-dilution adjustments for purchases of call option	7,033,470
Strike price per share	$55.91
Proceeds from sale of warrants	40,170,000
Liability component of convertible note	266,035,000	252,084,000
Accrued interest payment	1,750,000
Interest expense related to amortization of discount	13,951,000	12,959,000
Amortization of deferred financing costs	1,332,000	1,238,000
Interest expense related to contractual interest coupon of convertible notes	5,250,000	5,250,000
7.5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Aggregate principal amount of senior notes				475,000,000	300,000,000
Liability component of convertible note	775,000,000	775,000,000
Proceeds from issuance of senior notes				480,195,000	293,203,000
Effective interest rates				3.00%
Redemption of senior notes					35.00%
Equity offerings redemption price					107.50%
Accrued interest payment	$7,266,000

Recovered_Sheet4

Accumulated Other Comprehensive Income (Loss) - Schedule of Changes in Accumulated Other Comprehensive Income Loss (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, net of tax	($2,062)	$28,833
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	136,097	-26,945
Foreign currency translations	-2,801	-667
Income tax effect	-48,995	9,701
Net of tax	84,301	-17,911
Amounts reclassified from accumulated other comprehensive income:
Net of tax	-1,076	12,984
Other comprehensive income (loss), net of tax	85,377	-30,895
Ending balance, net of tax	83,315	-2,062
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production	526	20,289
Derivative expense, net	-2,208
Income tax effect	606	-7,305
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, net of tax	-1,395	28,833	21,868
Other comprehensive income (loss) before reclassifications:
Change in fair value of derivatives	136,097	-26,945	41,209
Income tax effect	-48,995	9,701	-14,836
Net of tax	87,102	-17,244	26,373
Amounts reclassified from accumulated other comprehensive income:
Net of tax	-1,076	12,984	19,408
Other comprehensive income (loss), net of tax	88,178	-30,228	6,965
Ending balance, net of tax	86,783	-1,395	28,833
Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Amounts reclassified from accumulated other comprehensive income:
Operating revenue: oil/gas production	526	20,289	30,326
Derivative expense, net	-2,208
Income tax effect	606	-7,305	-10,918
Foreign Currency Items [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance, net of tax	-667
Other comprehensive income (loss) before reclassifications:
Foreign currency translations	-2,801	-667
Net of tax	-2,801	-667
Amounts reclassified from accumulated other comprehensive income:
Other comprehensive income (loss), net of tax	-2,801	-667
Ending balance, net of tax	($3,468)	($667)

ShareBased_Compensation_Additi

Share-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$17,051	$15,425	$13,399
Share-based compensation capitalized into oil and gas properties	5,797	5,078	4,288
Stock option granted	0	0	0
Exercise price of stock options outstanding, minimum	$6.97
Exercise price of stock options outstanding, maximum	$53.20
Restricted stocks issued, shares	674,904	848,498	670,818
Restricted stocks issued, value	24,593	17,487	21,085
Unrecognized compensation cost, weighted-average period of recognition	1 year 9 months 18 days
Unrecognized compensation cost	22,354
Adjustments to additional paid-in capital related to net tax effect of stock options exercises and restricted stock vesting	-54	-884	814
Adjustments to additional paid in capital, tax deficit of stock option exercises and restricted stock vesting	609
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation		15,405	13,308
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]
Share-based compensation		$20	$91
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

ShareBased_Compensation_Summar

Share-Based Compensation - Summary of Stock Option Activity under Plan (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Options outstanding
Options outstanding, beginning of period	331,174	411,794	438,394
Granted	0	0	0
Exercised	-250
Forfeited		-15,250	-4,200
Expired	-125,950	-65,370	-22,400
Options outstanding, end of period	204,974	331,174	411,794
Options exercisable, end of period	204,974	318,279	378,004
Options unvested, end of period		12,895	33,790
Options exercisable, end of period	204,974	318,279	378,004
Options unvested, end of period		12,895	33,790
Options outstanding, weighted average exercise price
Options outstanding, beginning of period	$39.37	$39.04	$38.76
Granted	$0	$0	$0
Exercised	$46.20
Forfeited		$42.45	$35.54
Expired	$48.21	$36.56	$34.25
Options outstanding, end of period	$33.94	$39.37	$39.04
Options exercisable, end of period	$33.94	$40.62	$41
Options unvested, end of period		$8.64	$17.17
Options outstanding
Options outstanding, end of period	2 years 4 months 24 days	2 years 2 months 12 days	2 years 9 months 18 days
Options exercisable, end of period	2 years 4 months 24 days	2 years 1 month 6 days	2 years 6 months
Options unvested, end of period	0 years	5 years	5 years 4 months 24 days
Options outstanding, end of period, aggregate intrinsic value
Options outstanding, end of period	$531	$1,708	$766
Options exercisable, end of period	531	1,373	459
Options unvested, end of period		$335	$307

ShareBased_Compensation_Summar1

Share-Based Compensation - Summary of Restricted Stock Activity under Plan (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Number of restricted shares
Restricted stock outstanding, beginning of period	1,258,053	1,108,874	923,740
Issuances	674,904	848,498	670,818
Lapse of restrictions	-598,796	-534,041	-462,141
Forfeitures	-31,055	-165,278	-23,543
Restricted stock outstanding, end of period	1,303,106	1,258,053	1,108,874
Weighted average fair value
Restricted stock outstanding, beginning of period	$23.92	$27.56	$20.08
Issuances	$36.44	$20.61	$31.43
Lapse of restrictions	$24.57	$25.45	$18.29
Forfeitures	$30.19	$26.43	$26.10
Restricted stock outstanding, end of period	$29.95	$23.92	$27.56

Share_Repurchase_Program_Addit

Share Repurchase Program - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	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, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls
	acre
Loss Contingencies [Line Items]
Lease of facilities, maturity year	2025
Payments related to lease obligations	$966	$597	$894
Contingent liability to surety insurance company	78,070
Commitments to use drilling rigs and acquisition of seismic data, value	352,660
Commitments to use drilling rigs and acquisition of seismic data, period	4 years
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
Legal settlement	18,373
Net mineral acres	33,000
Brokerage fee unpaid	1,119
Acquisition amount owed	17,254
Litigation settlement amount	2,119
Minimum potential range contingency loss	0
Maximum potential range contingency loss	2,119
Second Claim [Member]
Loss Contingencies [Line Items]
Litigation settlement amount	$1,000

Commitments_and_Contingencies_1

Commitments and Contingencies - Minimum Net Annual Commitments Under all Leases, Subleases and Contracts with Non-Cancelable Terms in Excess of 12 Months (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2015	$1,416
2016	1,571
2017	1,524
2018	1,339
2019	1,194
2020	1,206
2021	879
2022	779
2023	792
2024	805
2025	$474

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2007	20-May-11
Employee Benefit And Retirement Plans [Line Items]
Liability of vested benefits recorded in other long term liabilities	$858
Expenses related to incentive compensation bonus	10,361	15,340	8,113
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	1,989	1,793	1,759
Maximum Percentage of Deferred Compensation plan	100.00%
Plan assets included in other assets	8,425	8,248
Number of times of severance payments relating to annual base salary and any target bonus at one hundred percent level	2.99
Percentage of employer matching contribution under 401(k) plan	50.00%
Maximum gross-up payment to executives	110.00%
Amount of one week's pay of each full of annual pay under Employee severance Plan				$10,000
Period of involuntary termination of employment				6 months
Minimum [Member]
Employee Benefit And Retirement Plans [Line Items]
Maximum period of sum of payments and benefits under employee severance plan				84 days
Maximum [Member]
Employee Benefit And Retirement Plans [Line Items]
Maximum period of sum of payments and benefits under employee severance plan				12 months
2009 plan [Member]
Employee Benefit And Retirement Plans [Line Items]
Additional number of common stock to be issued under incentive stock options					2,800,000
Additional shares available for issuance	1,563,967
2009 plan [Member] | All Employee [Member]
Employee Benefit And Retirement Plans [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]
Employee Benefit And Retirement Plans [Line Items]
Vesting period of stock options	3 years
Period after which stock option will expire subsequent to award	10 years
Restricted Stock Grants [Member] | Minimum [Member]
Employee Benefit And Retirement Plans [Line Items]
Vesting period of stock options	1 year
Restricted Stock Grants [Member] | Maximum [Member]
Employee Benefit And Retirement Plans [Line Items]
Vesting period of stock options	3 years

Recovered_Sheet6

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Financial Data Related to Oil and Gas Producing Activities (Detail) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Accumulated DD&A:
Balance, beginning of year			($5,908,760)
Provision for DD&A			-340,006		-350,574		-344,365
Write-down of oil and gas properties	304,062	47,130	351,192
Balance, end of year	-6,970,631		-6,970,631		-5,908,760
Net proved oil and gas properties	1,846,637		1,846,637		1,895,357
Lease operating expenses			176,495		201,153		215,003
Transportation, processing and gathering expenses			64,951		42,172		21,782
Production taxes			12,151		15,029		10,015
Accretion expense			28,411		33,575		33,331
United States [Member]
Oil and gas properties, proved and unevaluated:
Balance, beginning of year			8,517,873		7,692,261		7,049,777
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties			44,634		70,903		102,807
Exploratory costs			270,850		297,113		81,458
Development costs			438,334	[1]	378,242	[1]	395,555	[1]
Salaries, general and administrative costs			33,975		32,815		25,318
Interest			45,722		46,860		37,656
Less: overhead reimbursements			-3,334		-321		-310
Total costs incurred during the year			830,181		825,612		642,484
Balance, end of year	9,348,054		9,348,054		8,517,873		7,692,261
Accumulated DD&A:
Balance, beginning of year			-5,908,760		-5,510,166		-5,174,729
Provision for DD&A			-335,987		-346,827		-341,096
Write-down of oil and gas properties			-351,192
Sale of proved properties			-374,692		-51,767		5,659
Balance, end of year	-6,970,631		-6,970,631		-5,908,760		-5,510,166
Net proved oil and gas properties	2,377,423		2,377,423		2,609,113		2,182,095
DD&A per Mcfe	3.59		3.59		3.43		3.69
Lease operating expenses			176,495		201,153		215,003
Transportation, processing and gathering expenses			64,951		42,172		21,782
Production taxes			12,151		15,029		10,015
Accretion expense			28,411		33,575		33,331
Expensed costs - United States			282,008		291,929		280,131
Canada [Member]
Oil and gas properties, proved and unevaluated:
Balance, beginning of year			10,583
Costs incurred during the year (capitalized):
Acquisition costs			6,956		8,764
Exploratory costs			19,040		1,819
Total costs incurred during the year			25,996		10,583
Balance, end of year	$36,579		$36,579		$10,583
[1]	Includes capitalized asset retirement costs of ($20,305), $54,737 and $95,293, respectively.

Recovered_Sheet7

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Financial Data Related to Oil and Gas Producing Activities (Parenthetical) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Asset retirement costs included in development cost	($20,305)	$54,737	$95,293

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Additional Information (Detail) (USD $)	3 Months Ended		9 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Project			Project
Reserve Quantities [Line Items]
Average 12-month oil prices net of differentials	89.46	94.94	94.94	89.46	102.21	101.2
Increase in written down value of oil and gas properties			$29,001	$13,342
Average 12-month gas prices net of differentials	3.68	4.19	4.19	3.68	3.66	2.68
Cost of revenues written down	304,062	47,130		351,192
Interest costs capitalized on unevaluated properties				45,722	46,860	37,656
Specifically identified drilling projects	108			108
Projects expected to be evaluated				4 years
Adoption of assumption due to revision of oil and gas reporting requirements				Using a historical 12-month average pricing assumption
Annual discount rate for discounting future cash flows				10.00%
Oil And Gas [Member]
Reserve Quantities [Line Items]
Cost of revenues written down			$47,130	$304,062
Natural Gas Liquids (MBbls) [Member]
Reserve Quantities [Line Items]
Average 12-month gas prices net of differentials	36.79	41.33	41.33	36.79
Extensions, discoveries and other additions				7,521	4,395	4,856
Sale of reserves primarily related to sale				556
Revisions of previous estimates				-331	2,439	9,349
Average 12-month natural gas liquids prices net of differentials	36.79			36.79	37.59	38.23
Appalachia drilling program [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions				118	117	162
Sale of reserves primarily related to sale				15
Deep gas development project at LaCantera [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions						17
Deep water drilling program [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions				116
GOM conventional shelf properties [Member]
Reserve Quantities [Line Items]
Sale of reserves primarily related to sale				63
Positive reserve report pricing changes [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates					18
Well performance [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates					55

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Net Costs Incurred on Unevaluated Properties (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Acquisition costs evaluated during the year	($42,384)	$30,271	$9,739
Exploration costs evaluated during the year	-186,308	188,830	-1,209
Capitalized interest costs evaluated during the year	45,722	46,860	37,656
Total costs incurred during the year, net of divestitures	($182,970)	$265,961	$46,186

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Financial Data Associated with Unevaluated Costs (Detail) (Unevaluated Costs [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unevaluated Costs [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$285,896
Exploration costs	167,510
Capitalized interest	113,959
Total unevaluated costs	567,365
Acquisition costs	7,330	82,990	24,736	170,840
Exploration costs	66,512	78,684	5,318	16,996
Capitalized interest	22,352	36,137	21,993	33,477
Total unevaluated costs	$96,194	$197,811	$52,047	$221,313

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Summary of Estimated Proved Oil and Natural Gas Reserve (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls	MBbls
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Estimated proved reserves, beginning balance	43,827	44,918	45,655
Revisions of previous estimates	-624	3,606	-1,559
Extensions, discoveries and other additions	9,650	2,367	3,681
Purchase of producing properties			4,336
Sale of reserves	-4,888	-170	-60
Production	-5,568	-6,894	-7,135
Estimated proved reserves, ending balance	42,397	43,827	44,918
Estimated proved developed reserves	22,957	27,920	29,005
Estimated proved undeveloped reserves	19,440	15,907	15,913
Natural Gas Liquids (MBbls) [Member]
Reserve Quantities [Line Items]
Estimated proved reserves, beginning balance	23,297	18,066	4,405
Revisions of previous estimates	-331	2,439	9,349
Extensions, discoveries and other additions	7,521	4,395	4,856
Purchase of producing properties			619
Sale of reserves	-556
Production	-2,114	-1,603	-1,163
Estimated proved reserves, ending balance	27,817	23,297	18,066
Estimated proved developed reserves	13,743	11,569	8,593
Estimated proved undeveloped reserves	14,074	11,728	9,473
Natural Gas (MMcfe) [Member]
Reserve Quantities [Line Items]
Estimated proved reserves, beginning balance	460,766	395,374	325,479
Revisions of previous estimates	-4,631	36,006	-26,694
Extensions, discoveries and other additions	131,617	79,729	131,408
Purchase of producing properties			8,168
Sale of reserves	-46,483	-214	-418
Production	-47,426	-50,129	-42,569
Estimated proved reserves, ending balance	493,843	460,766	395,374
Estimated proved developed reserves	249,924	246,946	210,956
Estimated proved undeveloped reserves	243,919	213,820	184,418
Oil And Natural Gas (MMcfe) [Member]
Reserve Quantities [Line Items]
Estimated proved reserves, beginning balance	863,513	773,285	625,839
Revisions of previous estimates	-10,362	72,275	20,050
Extensions, discoveries and other additions	234,639	120,299	182,633
Purchase of producing properties			37,895
Sale of reserves	-79,151	-1,235	-775
Production	-93,515	-101,111	-92,357
Estimated proved reserves, ending balance	915,124	863,513	773,285
Estimated proved developed reserves	470,118	483,885	436,540
Estimated proved undeveloped reserves	445,006	379,628	336,745

Supplemental_Information_on_Oi6

Supplemental Information on Oil and Natural Gas Operations - Unaudited - Summary of Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows	$6,635,751	$7,040,928	$6,295,455
Future production costs	-2,413,004	-2,062,657	-1,946,426
Future development costs	-1,511,687	-1,431,101	-1,241,531
Future income taxes	-609,516	-884,637	-799,007
Future net cash flows	2,101,544	2,662,533	2,308,491
10% annual discount	-682,752	-977,531	-794,632
Standardized measure of discounted future net cash flows	1,418,792	1,685,002	1,513,859
Changes in standardized measure of future net cash flows related to estimated proved oil and gas reserves
Standardized measure at beginning of year	1,685,002	1,513,859	1,542,962
Sales and transfers of oil, gas and NGLs produced, net of production costs	-486,232	-708,017	-697,741
Changes in price, net of future production costs	-864,118	229,425	-380,841
Extensions and discoveries, net of future production and development costs	549,649	155,592	178,272
Changes in estimated future development costs, net of development costs incurred during the period	203,026	28,684	212,329
Revisions of quantity estimates	-27,495	281,558	76,450
Accretion of discount	222,009	202,087	207,292
Net change in income taxes	209,323	-28,084	22,947
Purchases of reserves in-place			276,389
Sales of reserves in-place	-152,787	15,531	2,480
Changes in production rates due to timing and other	80,415	-5,633	73,320
Net increase (decrease) in standardized measure	-266,210	171,143	-29,103
Standardized measure at end of year	$1,418,792	$1,685,002	$1,513,859

Recovered_Sheet8

Summarized Quarterly Financial Information - Unaudited - Results of Operations by Quarter (Detail) (USD $)	3 Months Ended											12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenue	$184,780		$183,213		$207,046	$223,830	$239,253		$256,685	$245,877	$233,732	$795,542	$974,179	$951,489
Income (loss) from operations	-286,147	[1]	-34,356	[2]	16,613	48,552	37,206	[3]	62,422	69,525	72,828	-255,338	241,981	263,965
Net income (loss)	($190,515)	[1]	($29,415)	[2]	$4,444	$25,943	$1,752	[3],[4]	$36,102	$39,022	$40,758	($189,543)	$117,634	$149,426
Basic earnings (loss) per share	($3.47)		($0.54)		$0.08	$0.52	$0.04		$0.72	$0.78	$0.82	($3.60)	$2.36	$3.03
Diluted earnings (loss) per share	($3.47)		($0.54)		$0.08	$0.52	$0.04		$0.72	$0.78	$0.82	($3.60)	$2.36	$3.03
[1]	Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).
[2]	Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).
[3]	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
[4]	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

Recovered_Sheet9

Summarized Quarterly Financial Information - Unaudited - Results of Operations by Quarter (Parenthetical) (Detail) (USD $)	3 Months Ended			12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Write-down of oil and gas properties, before tax	$304,062	$47,130		$351,192
Write-down of oil and gas properties, after tax	194,600	30,163
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
Loss on early extinguishment of debt, after tax			$17,459

Recovered_Sheet10

Guarantor Financial Statements - Condensed Consolidating Balance Sheet (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$74,488		$331,224		$279,526	$38,451
Restricted cash	177,647
Accounts receivable	120,359		171,971
Fair value of derivative contracts	139,179		4,549
Current income tax receivable	7,212		7,366
Deferred taxes			31,710	[1]
Inventory	3,709		3,723
Other current assets	8,118		1,874
Total current assets	530,712		552,417
Oil and gas properties, full cost method:
Proved	8,817,268		7,804,117
Less: accumulated DD&A	-6,970,631		-5,908,760
Net proved oil and gas properties	1,846,637		1,895,357
Unevaluated	567,365		724,339
Other property and equipment, net	32,340		26,178
Fair value of derivative contracts	14,333		1,378
Other assets, net	27,224		48,887
Total assets	3,018,611		3,248,556
Current liabilities:
Accounts payable to vendors	132,629		195,677
Undistributed oil and gas proceeds	23,232		37,029
Accrued interest	9,022		9,022
Deferred taxes	20,119	[1]
Fair value of derivative contracts			7,753
Asset retirement obligations	69,400		67,161
Other current liabilities	49,505		54,520
Total current liabilities	303,907		371,162
Long-term debt	1,041,035		1,027,084
Deferred taxes	286,343	[1]	390,693	[1]
Asset retirement obligations	247,009		435,352
Fair value of derivative contracts			470
Other long-term liabilities	38,714		53,509
Total liabilities	1,917,008		2,278,270
Commitments and contingencies
Stockholders' equity:
Common stock	549		488
Treasury stock	-860		-860
Additional paid-in capital	1,633,307		1,397,885
Accumulated deficit	-614,708		-425,165
Accumulated other comprehensive income (loss)	83,315		-2,062		28,833
Total stockholders' equity	1,101,603		970,286
Total liabilities and stockholders' equity	3,018,611		3,248,556
Parent [Member]
Current assets:
Cash and cash equivalents	72,886		246,294		228,398	37,389
Restricted cash	177,647
Accounts receivable	73,711		74,887
Current income tax receivable	7,212		7,366
Deferred taxes	4,095		8,659	[1]
Inventory	1,011		3,440
Other current assets	8,112		1,874
Total current assets	344,674		342,520
Oil and gas properties, full cost method:
Proved	1,689,802		1,309,527
Less: accumulated DD&A	-970,387		-459,932
Net proved oil and gas properties	719,415		849,595
Unevaluated	289,556		325,113
Other property and equipment, net	32,340		26,178
Other assets, net	20,857		45,410
Investment in subsidiary	1,050,546		747,472
Total assets	2,457,388		2,336,288
Current liabilities:
Accounts payable to vendors	74,756		173,147
Undistributed oil and gas proceeds	22,158		34,386
Accrued interest	9,022		9,022
Other current liabilities	49,306		53,682
Total current liabilities	155,242		270,237
Long-term debt	1,041,035		1,027,084
Deferred taxes	117,206	[1]	10,227	[1]
Asset retirement obligations	3,588		4,945
Other long-term liabilities	38,714		53,509
Total liabilities	1,355,785		1,366,002
Commitments and contingencies
Stockholders' equity:
Common stock	549		488
Treasury stock	-860		-860
Additional paid-in capital	1,633,307		1,397,885
Accumulated deficit	-614,708		-425,165
Accumulated other comprehensive income (loss)	83,315		-2,062
Total stockholders' equity	1,101,603		970,286
Total liabilities and stockholders' equity	2,457,388		2,336,288
Guarantor Subsidiary [Member]
Current assets:
Cash and cash equivalents	1,450		84,290		51,128	926
Accounts receivable	46,615		97,128
Fair value of derivative contracts	139,179		4,549
Deferred taxes			23,051	[1]
Inventory	2,698		283
Total current assets	189,942		209,301
Oil and gas properties, full cost method:
Proved	7,127,466		6,494,590
Less: accumulated DD&A	-6,000,244		-5,448,828
Net proved oil and gas properties	1,127,222		1,045,762
Unevaluated	241,230		388,643
Fair value of derivative contracts	14,333		1,378
Other assets, net	1,360		1,349
Total assets	1,574,087		1,646,433
Current liabilities:
Accounts payable to vendors	57,873		22,530
Undistributed oil and gas proceeds	1,074		2,643
Deferred taxes	24,214	[1]
Fair value of derivative contracts			7,753
Asset retirement obligations	69,400		67,161
Other current liabilities	199		838
Total current liabilities	152,760		100,925
Deferred taxes	169,137	[1]	380,466	[1]
Asset retirement obligations	243,421		430,407
Fair value of derivative contracts			470
Total liabilities	565,318		912,268
Commitments and contingencies
Stockholders' equity:
Additional paid-in capital	1,362,684		1,309,563
Accumulated deficit	-440,699		-574,003
Accumulated other comprehensive income (loss)	86,784		-1,395
Total stockholders' equity	1,008,769		734,165
Total liabilities and stockholders' equity	1,574,087		1,646,433
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	152		640			136
Accounts receivable	33
Other current assets	6
Total current assets	191		640
Oil and gas properties, full cost method:
Unevaluated	36,579		10,583
Other assets, net	5,007		2,128
Investment in subsidiary	41,638		12,711
Total assets	83,415		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	90,339		27,403
Accumulated deficit	12		-52
Accumulated other comprehensive income (loss)	-6,936		-1,333
Total stockholders' equity	83,415		26,018
Total liabilities and stockholders' equity	83,415		26,062
Eliminations [Member]
Current assets:
Accounts receivable			-44
Deferred taxes	-4,095
Total current assets	-4,095		-44
Oil and gas properties, full cost method:
Investment in subsidiary	-1,092,184		-760,183
Total assets	-1,096,279		-760,227
Current liabilities:
Accounts payable to vendors			-44
Deferred taxes	-4,095	[1]
Total current liabilities	-4,095		-44
Total liabilities	-4,095		-44
Commitments and contingencies
Stockholders' equity:
Additional paid-in capital	-1,453,023		-1,336,966
Accumulated deficit	440,687		574,055
Accumulated other comprehensive income (loss)	-79,848		2,728
Total stockholders' equity	-1,092,184		-760,183
Total liabilities and stockholders' equity	($1,096,279)		($760,227)
[1]	Deferred income taxes have been allocated to Guarantor Subsidiary where related oil and gas properties reside.

Recovered_Sheet11

Guarantor Financial Statements - Condensed Consolidating Statement of Operations (Detail) (USD $)	3 Months Ended											12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenue:
Oil production												$516,104	$715,104	$761,304
Natural gas production												166,494	190,580	134,739
Natural gas liquids production												85,642	60,687	48,498
Other operational income												7,951	7,808	3,520
Derivative income, net												19,351		3,428
Total operating revenue	184,780		183,213		207,046	223,830	239,253		256,685	245,877	233,732	795,542	974,179	951,489
Operating expenses:
Lease operating expenses												176,495	201,153	215,003
Transportation, processing and gathering expenses												64,951	42,172	21,782
Production taxes												12,151	15,029	10,015
Depreciation, depletion, amortization												340,006	350,574	344,365
Write-down of oil and gas properties	304,062		47,130									351,192
Accretion expense												28,411	33,575	33,331
Salaries, general and administrative												66,451	59,524	54,648
Franchise tax settlement							12,590						12,590
Incentive compensation expense												10,361	15,340	8,113
Other operational expenses												862	151	267
Derivative expense, net													2,090
Total operating expenses												1,050,880	732,198	687,524
Income (loss) from operations	-286,147	[1]	-34,356	[2]	16,613	48,552	37,206	[3]	62,422	69,525	72,828	-255,338	241,981	263,965
Other (income) expenses:
Interest expense												38,855	32,837	30,375
Interest income												-574	-1,695	-600
Other income												-2,332	-2,799	-1,805
Other expense												274
Loss on early extinguishment of debt							27,279						27,279	1,972
Total other (income) expenses												36,223	55,622	29,942
Income (loss) before taxes												-291,561	186,359	234,023
Provision (benefit) for income taxes:
Current												159	-10,904	15,022
Deferred												-102,177	79,629	69,575
Total income taxes												-102,018	68,725	84,597
Net income (loss)	-190,515	[1]	-29,415	[2]	4,444	25,943	1,752	[3],[4]	36,102	39,022	40,758	-189,543	117,634	149,426
Comprehensive income (loss)												-104,166	86,739	156,391
Parent [Member]
Operating revenue:
Oil production												29,701	30,475	26,149
Natural gas production												86,812	68,895	34,331
Natural gas liquids production												61,200	32,293	15,264
Other operational income												7,551	7,163	2,766
Total operating revenue												185,264	138,826	78,510
Operating expenses:
Lease operating expenses												18,719	14,680	19,914
Transportation, processing and gathering expenses												53,028	28,322	12,049
Production taxes												8,324	6,229	3,330
Depreciation, depletion, amortization												138,313	93,579	63,022
Write-down of oil and gas properties												351,192
Accretion expense												230	372	561
Salaries, general and administrative												66,430	59,473	54,641
Franchise tax settlement													12,590
Incentive compensation expense												10,361	15,340	8,113
Other operational expenses												669	38	173
Total operating expenses												647,266	230,623	161,803
Income (loss) from operations												-462,002	-91,797	-83,293
Other (income) expenses:
Interest expense												38,810	32,816	30,446
Interest income												-333	-1,480	-285
Other income												-836	-875	-144
Other expense												274
Loss on early extinguishment of debt													27,279	1,972
(Income) loss from investment in subsidiaries												-133,336	-214,983	-223,555
Total other (income) expenses												-95,421	-157,243	-191,566
Income (loss) before taxes												-366,581	65,446	108,273
Provision (benefit) for income taxes:
Current												159	-10,904	15,022
Deferred												-177,197	-41,284	-56,175
Total income taxes												-177,038	-52,188	-41,153
Net income (loss)												-189,543	117,634	149,426
Comprehensive income (loss)												-104,166	86,739	156,391
Guarantor Subsidiary [Member]
Operating revenue:
Oil production												486,403	684,629	735,155
Natural gas production												79,682	121,685	100,408
Natural gas liquids production												24,442	28,394	33,234
Other operational income												400	645	397
Derivative income, net												19,351		3,428
Total operating revenue												610,278	835,353	872,622
Operating expenses:
Lease operating expenses												157,776	186,473	195,105
Transportation, processing and gathering expenses												11,923	13,850	9,733
Production taxes												3,827	8,800	6,685
Depreciation, depletion, amortization												201,693	256,995	281,152
Accretion expense												28,181	33,203	32,513
Salaries, general and administrative												4	5	7
Other operational expenses												193	113	94
Derivative expense, net													2,090
Total operating expenses												403,597	501,529	525,289
Income (loss) from operations												206,681	333,824	347,333
Other (income) expenses:
Interest expense												45	21	-71
Interest income												-192	-195	-315
Other income												-1,496	-1,924	-1,661
(Income) loss from investment in subsidiaries														75
Total other (income) expenses												-1,643	-2,098	-1,972
Income (loss) before taxes												208,324	335,922	349,305
Provision (benefit) for income taxes:
Deferred												75,020	120,913	125,750
Total income taxes												75,020	120,913	125,750
Net income (loss)												133,304	215,009	223,555
Comprehensive income (loss)												133,304	215,009	223,555
Non-Guarantor Subsidiaries [Member]
Operating revenue:
Other operational income														357
Total operating revenue														357
Operating expenses:
Lease operating expenses														-16
Depreciation, depletion, amortization														191
Accretion expense														257
Salaries, general and administrative												17	46
Total operating expenses												17	46	432
Income (loss) from operations												-17	-46	-75
Other (income) expenses:
Interest income												-49	-20
(Income) loss from investment in subsidiaries												-32	26
Total other (income) expenses												-81	6
Income (loss) before taxes												64	-52	-75
Provision (benefit) for income taxes:
Net income (loss)												64	-52	-75
Comprehensive income (loss)												64	-52	-75
Eliminations [Member]
Other (income) expenses:
(Income) loss from investment in subsidiaries												133,368	214,957	223,480
Total other (income) expenses												133,368	214,957	223,480
Income (loss) before taxes												-133,368	-214,957	-223,480
Provision (benefit) for income taxes:
Net income (loss)												-133,368	-214,957	-223,480
Comprehensive income (loss)												($133,368)	($214,957)	($223,480)
[1]	Includes a write-down of oil and gas properties of $304,062 before income tax effect ($194,600 net of income tax effect).
[2]	Includes a write-down of oil and gas properties of $47,130 before income tax effect ($30,163 net of income tax effect).
[3]	Includes franchise tax settlement of $12,590 before income tax effect ($8,058 net of income tax effect).
[4]	Includes loss on early extinguishment of debt of $27,279 before income tax effect ($17,459 net of income tax effect).

Guarantor_Financial_Statements2

Guarantor Financial Statements - Condensed Consolidating Statement of Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	($189,543)	$117,634	$149,426
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	340,006	350,574	344,365
Write-down of oil and gas properties	351,192
Accretion expense	28,411	33,575	33,331
Deferred income tax (benefit) provision	-102,177	79,629	69,575
Settlement of asset retirement obligations	-56,409	-83,854	-65,567
Non-cash stock compensation expense	11,325	10,347	8,699
Excess tax benefits		-156	-949
Non-cash derivative expense	-18,028	2,239	-509
Loss on early extinguishment of debt		27,279	1,972
Non-cash interest expense	16,661	16,219	13,085
Change in current income taxes	158	2,767	10,618
(Increase) decrease in accounts receivable	51,611	-4,683	-55,871
(Increase) decrease in other current assets	-6,244	1,752	-2,836
(Increase) decrease in inventory		583	436
Decrease in accounts payable	-3,419	402	5,101
Decrease in other current assets	-19,152	42,451	-10,426
Other	-3,251	-2,553	9,299
Net cash provided by (used in) operating activities			509,749
Net cash provided by operating activities	401,141	594,205	509,749
Cash flows from investing activities:
Investment in oil and gas properties	-927,247	-663,299	-555,855
Proceeds from sale of oil and gas properties, net of expenses	242,914	48,821	403
Sale of fixed assets			134
Investment in fixed and other assets	-10,182	-6,816	-13,370
Change in restricted funds	-178,072	-1,742
Net cash used in investing activities	-872,587	-623,036	-568,688
Cash flows from financing activities:
Proceeds from bank borrowings			25,000
Proceeds from issuance of common stock	225,999
Repayment of bank borrowings			-70,000
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	-3,371	-9,065	-11,966
Redemption of senior subordinated notes			-200,681
Redemption of senior notes		-396,014
Excess tax benefits		156	949
Net payments for share-based compensation	-7,182	-3,733	-3,773
Net cash provided by financing activities	215,446	80,594	300,014
Effect of exchange rate changes on cash	-736	-65
Net change in cash and cash equivalents	-256,736	51,698	241,075
Cash and cash equivalents, beginning of year	331,224	279,526	38,451
Cash and cash equivalents, end of year	74,488	331,224	279,526
Parent [Member]
Cash flows from operating activities:
Net income (loss)	-189,543	117,634	149,426
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	138,313	93,579	63,022
Write-down of oil and gas properties	351,192
Accretion expense	230	372	561
Deferred income tax (benefit) provision	-177,197	-41,284	-56,175
Settlement of asset retirement obligations	-201
Non-cash stock compensation expense	11,325	10,347	8,699
Excess tax benefits		-156	-949
Loss on early extinguishment of debt		27,279	1,972
Non-cash interest expense	16,661	16,219	13,085
Non-cash (income) loss from investment in subsidiaries	-133,336	-214,983	-223,555
Change in current income taxes	158	2,767	10,618
Change in intercompany receivables/payables	114,056	186,903	275,819
(Increase) decrease in accounts receivable	1,131	-15,630	-22,750
(Increase) decrease in other current assets	-6,238	1,752	-2,836
(Increase) decrease in inventory	2,415	583	436
Decrease in accounts payable	-662	-1,052	5,348
Decrease in other current assets	-16,946	40,543	-5,311
Other	-1,755	419	10,960
Net cash provided by (used in) operating activities			228,370
Net cash provided by operating activities	109,603	225,292
Cash flows from investing activities:
Investment in oil and gas properties	-338,731	-273,474	-324,542
Proceeds from sale of oil and gas properties, net of expenses	28,103	6,300	403
Sale of fixed assets			134
Investment in fixed and other assets	-10,182	-6,816	-13,370
Change in restricted funds	-177,647
Investment in subsidiaries		-14,000
Net cash used in investing activities	-498,457	-287,990	-337,375
Cash flows from financing activities:
Proceeds from bank borrowings			25,000
Proceeds from issuance of common stock	225,999
Repayment of bank borrowings			-70,000
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	-3,371	-9,065	-11,966
Redemption of senior subordinated notes			-200,681
Redemption of senior notes		-396,014
Excess tax benefits		156	949
Net payments for share-based compensation	-7,182	-3,733	-3,773
Net cash provided by financing activities	215,446	80,594	300,014
Net change in cash and cash equivalents	-173,408	17,896	191,009
Cash and cash equivalents, beginning of year	246,294	228,398	37,389
Cash and cash equivalents, end of year	72,886	246,294	228,398
Guarantor Subsidiary [Member]
Cash flows from operating activities:
Net income (loss)	133,304	215,009	223,555
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	201,693	256,995	281,152
Accretion expense	28,181	33,203	32,513
Deferred income tax (benefit) provision	75,020	120,913	125,750
Settlement of asset retirement obligations	-56,208	-83,854	-65,567
Non-cash derivative expense	-18,028	2,239	-509
Non-cash (income) loss from investment in subsidiaries			75
Change in intercompany receivables/payables	-145,250	-186,947	-275,125
(Increase) decrease in accounts receivable	50,514	10,947	-33,345
(Increase) decrease in inventory	-2,415
Decrease in accounts payable	-2,757	1,454	-208
Decrease in other current assets	-2,206	1,908	-5,115
Other	-1,496	-2,972	-1,661
Net cash provided by (used in) operating activities			281,515
Net cash provided by operating activities	260,352	368,895
Cash flows from investing activities:
Investment in oil and gas properties	-558,003	-378,254	-231,313
Proceeds from sale of oil and gas properties, net of expenses	214,811	42,521
Net cash used in investing activities	-343,192	-335,733	-231,313
Cash flows from financing activities:
Net change in cash and cash equivalents	-82,840	33,162	50,202
Cash and cash equivalents, beginning of year	84,290	51,128	926
Cash and cash equivalents, end of year	1,450	84,290	51,128
Non-Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net income (loss)	64	-52	-75
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			191
Accretion expense			257
Non-cash (income) loss from investment in subsidiaries	-32	26
Change in intercompany receivables/payables	31,194	44	-694
(Increase) decrease in accounts receivable	-34		224
(Increase) decrease in other current assets	-6
Decrease in accounts payable			-39
Net cash provided by (used in) operating activities			-136
Net cash provided by operating activities	31,186	18
Cash flows from investing activities:
Investment in oil and gas properties	-30,513	-11,571
Change in restricted funds	-425	-1,742
Investment in subsidiaries	-31,696	-13,404
Net cash used in investing activities	-62,634	-26,717
Cash flows from financing activities:
Equity proceeds from parent	31,696	27,404
Net cash provided by financing activities	31,696	27,404
Effect of exchange rate changes on cash	-736	-65
Net change in cash and cash equivalents	-488	640	-136
Cash and cash equivalents, beginning of year	640		136
Cash and cash equivalents, end of year	152	640
Eliminations [Member]
Cash flows from operating activities:
Net income (loss)	-133,368	-214,957	-223,480
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash (income) loss from investment in subsidiaries	133,368	214,957	223,480
Cash flows from investing activities:
Investment in subsidiaries	31,696	27,404
Net cash used in investing activities	31,696	27,404
Cash flows from financing activities:
Equity proceeds from parent	-31,696	-27,404
Net cash provided by financing activities	($31,696)	($27,404)